Well Logging

Markus Bernhart

Baccalaurea Thesis Well Logging

Supervised by: Approval date:

Date: 27/05/2014

Prof. Dr. Franz Kessler 24th January 2006

Table of Contents 1. Introduction ................................................................................................................................... 4 1.1 Overview ................................................................................................................................................... 4 1.2 History of logging ...................................................................................................................................... 7

2. Basics ............................................................................................................................................. 9 2.1 Basic Log Types ....................................................................................................................................... 9 2.1.1 Logging While Drilling (LWD) ............................................................................................................................... 9 2.1.2 Wireline Openhole Logging ................................................................................................................................ 10 2.1.3 Wireline Cased Hole Logging ............................................................................................................................. 11 2.1.4 Pipe Conveyed Logging ..................................................................................................................................... 11

2.2 Logging Contracts .................................................................................................................................. 11 2.3 Preparing a Logging Program................................................................................................................ 13 2.4 Operational Decisions ............................................................................................................................ 13 2.4.1 Tool failures......................................................................................................................................................... 14 2.4.2 Stuck tools........................................................................................................................................................... 14

2.5 Coring ...................................................................................................................................................... 15 2.5.1 Core Acquisition .................................................................................................................................................. 15 2.5.2 Conventional Core Analysis ............................................................................................................................... 15 2.5.3 Special Core Analysis ......................................................................................................................................... 16 2.5.4 Limitations of core measurements ..................................................................................................................... 17

2.6 Wellsite mud logging .............................................................................................................................. 17

3. Quicklook log interpretation ..................................................................................................... 19 3.1 Basic quality control ................................................................................................................................ 19 3.2 Identifying the reservoir .......................................................................................................................... 20 3.3 Identifying the fluid type and contacts.................................................................................................... 21 3.4 Calculating the porosity .......................................................................................................................... 23 3.5 Calculating hydrocarbon saturation ....................................................................................................... 24 3.6 Presenting the results ............................................................................................................................. 25 3.7 Pressure/sampling .................................................................................................................................. 26 3.8 Permeability determination..................................................................................................................... 28

4. Full interpretation ....................................................................................................................... 30 4.1 Net sand definition .................................................................................................................................. 30 4.2 Porosity calculation ................................................................................................................................. 31 4.3 Archie saturation ..................................................................................................................................... 32 4.4 Permeability ............................................................................................................................................ 32

5. Value of information ................................................................................................................... 35 References ....................................................................................................................................... 38

List of Figures 1 Schematic sketch of a wireline logging operation (left) and logging while drilling......................... 4 2 From measurement to production. The fields of geophysics, geology and petrophysicist may overlap a bit. ................................................................................................................................. 5 3 Sketch of an optimally drained complex off shore lithology, achieved by drilling vertical, deviated and horizontal wells ............................................................................................................................. 6 4 First continuous well log (Pechelbronn, September 5, 1927), with a depth interval from about 170 to 270meters. ................................................................................................................................... 7 5 The first logging operation in an oil well (left), Henry Doll who calibrates a teleclinometer to measure the azimuth and angle of the borehole drift (middle) and a logging unit, recording two curves somewhere I California, in 1932.................................................................................................. 7 6 Modern logging unit, doing measurements in Tyler, Texas in 1997. A fully computerized truck for logging, including a satellite dish for data transmission. ............................................................ 8 7 Identifying net reservoir.................................................................................................................. 20 8 Identifying net pay .......................................................................................................................... 21 9 Identifying gas sands from Vp/Vs versus Vp plot ........................................................................... 22 10 Selection of the fluid density for porosity calculation, using a density tool ................................ 22 11 Pickett Plot ................................................................................................................................... 24 12 A report of the evaluated results ................................................................................................. 26 13 Formation pressure plot .............................................................................................................. 27 14 Typical viscosities of borehole fluids ........................................................................................... 28 15 Typical behaviour of the pressure during a pretest .................................................................... 29 16 Determination of reservoir cut-offs by using a GR-density cross plot ....................................... 30 17 Porosity calibrated by a core ....................................................................................................... 31 18 Effect of kv / kh < 1 in horizontal wells on the permeability ......................................................... 33 19 The costs for information ............................................................................................................. 35 20 Decision tree ................................................................................................................................ 36 21 ΔEMV versus R ........................................................................................................................... 37

Well Logging

1. Introduction

1.1 Overview In the oil industry the method of wireline logging was developed to be able to measure the properties of the rocks surrounding the borehole, especially to identify and evaluate hydrocarbon-bearing strata. Therefore a sonde containing one or more sensors, which is pulled uphole on a cable with a winch is lowered into the borehole. Classically, three types of measurements are distinguished: Electrical, acoustic and nuclear. A significant number of textbooks have been written on the subject in the 1980s. Additionally, the oil service companies (e.g. Schlumberger) have published documents on log interpretation principles and logging chart books. Some of these books are used by graduate students and professionals, while others are compendium like references.

1 Schematic sketch of a wireline logging operation (left) and logging while drilling

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Well Logging

These publications occurred because there was a need from the geological community, but also as a result of new technological advances that brought more useful measurements to the earth scientists. The oil crisis of the 1980s led to a noticeable acceleration in logging developments in the last twenty years. That was driven by several external factors: 

Drilling Technology. The logging industry was challenged in many ways by directional and particularly horizontal wells. The most significant development is a full line of Logging-While-Drilling (LWD) tools, which are deployed in the bottom-hole assembly and which acquire and transmit data in real time, even while the well is being drilled (Figure 1.1). The data is recorded at an early stage when the borehole is very little influenced by fluid invasion and borehole damage effects, what simplifies the identification and evaluation of hydrocarbon-bearing regions. LWD is also used for geosteering where well drilling is monitored and adjusted, usually by comparing the downhole data with computed data of a geological model. Additionally LWD is used to decide on coring and casing points. Therefore a sensor is positioned directly after drill bit.

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Electronics and Computing. Only the electronic revolution made the development of the modern high-data-rate tools (imaging tools, array sensor tools, etc.) possible. The bottom-hole assembly is equipped with several downhole sensors and downhole microprocessors, which control the acquisition and store the data in memories, also placed downhole. Surface computers receive data from downhole and display it on monitors. Data transmission via satellite brings the data to the user’s office practically in real time, to make him able to evaluate them and make rapid decisions.

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New Targets. In the last fifteen to twenty five years, the most significant move is towards deeper water targets, a development linked to new drilling technologies, but also to new geological insights. Discoveries in deep water offshore have been of impressive sizes initiated a race to deeper water plays. These reservoirs are often geologically young, poorly consolidated, highly porous and thinly bedded. Therefore robust sensors of sufficiently high vertical resolution that work even in poor borehole conditions which are often given in these environments had to be developed. Modern logging tools often make a measurement every 1.2 inches, rather than the conventional 6 inches. Highest vertical resolutions are achieved by an electrical imaging measurement and are about 0.4 inches. Other challenging targets content fractured basement rocks (for geothermal energy, but also for oil), coal beds (for methane), environmental logging (to detect pollutants), ultra deep research wells and mineral mining wells. Often techniques from the oil companies can be used, but in some instances entirely new techniques have to be developed.

2 From measurement to production. The fields of geophysics, geology and petrophysicist may overlap a bit.

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Well Logging

Methods of logging have broadened their scope significantly and today address a much wider range of users with more adequate tools. Currently used techniques in surface geophysics, logging, sampling and flow measurements are listed in the first column of Figure 1.1.2, while the second one shows a simplified and schematic way of the reservoir properties. The third column contains the “elements” of reservoir characterization, or those overall aspects of s reservoir that allow us to understand its composition and behaviour: the architecture and internal layering, the reserves and flow units. Finally in the last column there is the only tangible of ultimate relevance in the oil industry: production or return on investment. Many of the measurements in the figure above have been improved in the last few years or are completely new. They make it possible for the geoscientists and engineers to improve their work, resulting in a better, more complete assessment of reservoir. Especially tools for geological measurements have been developed significantly, what means that they are rarely standardized on a logging program and have only been built in very small numbers. By this reason they are known as “specialty tools” or “niche tools”.

3 Sketch of an optimally drained complex off shore lithology, achieved by drilling vertical, deviated and horizontal wells

Petroleum professionals are allowed to do field development with almost surgical precision because of new drilling technology, new logging and 3-D seismic surveys. The petroleum engineer is able to target oil in bypassed zones, drain narrow fluvial point bars along the optimum direction, or intersect fractures at the best angle to optimize production. For this process, real-time measurements during drilling, fast data processing and the possibility to make on site decisions are important elements. Drilling and evaluating wells in a “geologically real” way represents a major advance in reservoir development. In Figure 1.3 a field with several deviated and horizontal wells is shown. This field had to be carefully designed and drilled, so that the various compartments could be reached for optimized reservoir drainage without the wells coming to close to each other.

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Well Logging

1.2 History of logging The first person who did some logs was perhaps Professor Forbes from the Edinburgh Observatory. In the time from 1837 to 1842 ho lowered some temperature sensors up to 24 feet deep into the ground, to record temperature variation with depth and time. These data were then analysed by the physicist Lord Kelvin (Thompson, 1861), who needed them to calculate the age of the earth. Temperature measurements are still done, but only for being a use in calibrating other tools. Well logging started to become commercial with the two French brothers, Conrad Schlumberger (1878 – 1936), who graduated from the Ecole Polytechnique France as a physicist, and Marcel Schlumberger (1884 – 1953), an engineer from the Ecole Centrale de Paris. Their father Paul, a business man, supported their ideas. It was them, who tried the first electrical measurements (at the surface), in particular for locating iron and copper deposits. After having some success in several countries, they created the Société de Prospection Electrique (SPE). Marcel tried the first resistivity tool in a borehole in 1921. The result of this measurement convinced them to pursue this further. In 1927, Conrad outlined the principle of “electrical coring”. They hired Henry Doll to develop the equipment and conduct the first oil well operation (5th September, 1927), which took place in Pechelbronn in Alsace, where the oil industry just started to grow.

4 First continuous well log (Pechelbronn, September 5, 1927), with a depth interval from about 170 to 270meters.

The hand drawn resulting log represents a turning point in oil exploration. Then they knew that major subsurface geological formations could easily be identified. It was clear that using measured data from nearby wells and doing some correlations would give more accurate results than drilling cuttings, and more cost effective than core drilling. Furthermore, the technique had potential for detecting hydrocarbon bearing layers, but this could not be demonstrated in Pechelbronn, because the pay zones were too thin. After convincing the Royal Dutch Shell that the technique was reliable, they got a logging contract for Venezuela. The company expanded to India and Russia and, by the help of discovering the spontaneous potential (SP), the United States, where there were some initial problems.

5 The first logging operation in an oil well (left), Henry Doll who calibrates a teleclinometer to measure the azimuth and angle of the borehole drift (middle) and a logging unit, recording two curves somewhere I California, in 1932.

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Well Logging

6 Modern logging unit, doing measurements in Tyler, Texas in 1997. A fully computerized truck for logging, including a satellite dish for data transmission.

By combining the two measurements, hydrocarbon bearing strata could be located. Now the way was opened for well logging to become an own industry. In 1934 the Schlumberger Well Services Company was found in Houston, Texas, expanded rapidly and the number of crews got higher and higher (1 crew in 1928  about 1100 crews in 2000). Improvements and new developments followed the present situation, where various techniques are used to measure various values and well logging is more accurate than in the old days. Some important techniques and basics are explained in the following chapters.

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Well Logging

2. Basics 2.1 Basic Log Types A list of the log types that may be run and why they are run is given below.

2.1.1 Logging While Drilling (LWD) Petrophysicists were used only to wireline logging, what means the data acquired by running tools on a cable after the hole had been drilled. But nowadays advances in drilling and logging technologies allow the acquisition of log data via tools which are placed in the actual drilling assembly. These tools may transmit data to the surface in real-time basis or store the data in a downhole memory from which it may be downloaded when the assembly is brought back to the surface. LWD tools lead to a complication during the drilling process, as well as they mean additional costs. However, their use may be justified when: 

Real-time information is needed for operational reasons, such as steering a well in a particular formation, picking up formation tops, coring points and casing setting depths

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Saving information if there is a risk of losing the hole

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Acquisition of data while drilling horizontally, where wireline logging leads to problems

The LWD data may be received either by transmission via mud pulses in real time while drilling or by storing the data downhole in the tools memory and retrieving it when the tool is brought to the surface. Typically both modes will be used, with the memory data superseding the pulsed data once the tool is retrieved. Some factors may limit the ability to use both sets of data, which are: 

Drilling mode: Mud pulses can only be sent when there is mud pumped through the drillstring

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Battery life: The tools in the string can save memory only for 40 - 90 hours, depending on the tools which are in use

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Memory size: Most LWD tools have a memory capacity of a few megabytes. As soon as the memory is full, the data is started to be overwritten. Dependent on the log parameters the memory will be full after 20 – 120 hours

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Tool failure: It is common in using LWD tools that either the transmission or record ability can be disturbed

Some of the recorded data may be useable only if the toolstring is rotating while drilling, which may not always be the case if a steerable mud motor is being used. Then the petrophysicist may need to request drilling to reacquire data over particular intervals while in reaming/rotating mode. This may also be needed if the rate of penetration (ROP) is so high that it affects the accuracy of statistically based tools (e.g. density, neutron) or the sampling interval for tools working on a fixed sampling increment. Another important consideration is how close the LWD tools can be positioned to the bit in the drill string. The petrophysicist would want them as close to the bit as possible, but there are some limitation because of the drilling operation, like the ability of steering the well and achieve a high rate of penetration, which is influenced by the LWD toolstring. Typically required LWD data includes the following: 

GR: Natural gamma ray emission from the formation

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Density: formation density as measured by gamma ray Compton scattering via a radioactive source and gamma ray detectors. This may also include a photoelectric effect (Pe) measurement.

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Well Logging

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Neutron porosity: Formation density derived from the hydrogen index (HI) as measured by the gamma rays emitted when injected thermal or epithermal neutrons from a source in the string are captured in the formation

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Sonic: The transit time of sound waves in the formation

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Resistivity: The formation resistivity for multiple depth of investigation as measured by an induction-type wave resistivity tool

LWD-GR, -density, -neutron as separate up/down or left/right curves, separating the contributions from different quadrants in the borehole is offered by some contractors. This may be extremely useful in steering horizontal wells, where it is important to determine neighbouring formation boundaries before they are penetrated. With the resistivity data borehole resistivity images are produced. That can be used to establish the stratigraphic or sedimentary dip and/or presence of fractures/vugs. New types of tools for LWD, which are in development now, include nuclear magnetic resonance (NMR), formation pressure, and shear sonic.

2.1.2 Wireline Openhole Logging After a section of well is completed, the bit is pulled out and there is an opportunity to do Openhole logs either on the wireline or on the drillstring before the hole is closed or abandoned. Additionally to the wireline versions of the LWD tools described above, following tools may be run: 

Gamma Ray: With this tool the natural radioactivity of the formation can be measured. This is important to distinguish between sands and shales in siliciclastic environments.

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Natural gamma ray spectroscopy: It works like the gamma ray, but it also separates the gamma ray counts into three energy windows to determine the different sources of the radioactivity in the formation which are uranium, potassium and thorium. With this additional information it is possible to estimate the relative proportions of certain minerals in the formation.

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Caliper: It measures the diameter of the hole with either two, four or even more arms and sends the data to the surface.

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Density: The difference to tho LWD tool is that the wireline version of this tool has a much stronger source and also includes a Pe curve, which is useful in complex formation evaluation.

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Neutron porosity: The standardized device is a thermal neutron, while newer ones often use epithermal (advantage of less salinity dependence), which rely on minitrone-type neutron generators rather than chemical sources

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Full-waveform sonic: Advanced tools may measure the shear velocity, Stonely velocity, and various other sound modes in the borehole and the formation, additionally to the basic compressional velocity.

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Resistivity: There are two main categories of these tools: laterolog and induction type. Laterolog tools measure the potential, caused by a low frequency source, over an array of detectors. Induction-type tools induce eddy currents in the formation via primary coils and then, a secondary array of coils to measure the magnetic fields caused by these currents. They can be used in oil based mud systems because of their high frequencies. There are tools for different depths of investigation, the shallower the depth, the better the vertical resolution.

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Microresistivity: With these tools the formation resistivity in the invaded zone close to the borehole wall can be measured. Low frequency current is used, what means that they are not suitable in oil-based mud. The estimation of the invaded zone saturation and picking up bedding features too small to be resolved by the deeper reading tools is done by these tools.

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Well Logging

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Imaging tools: They work either acoustic or a resistivity principle and are designed to provide an image of the borehole wall and to give us information about stratigraphic r sedimentary dip and/or presence of fractures/vugs.

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Formation pressure sampling: They acquire formation samples and/or measure the formation pressure at a discrete point in the system.

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Sidewall sampling: It’s an explosive-type device which shoots a sampling bullet into the borehole wall that is retrieved by a cable linking the gun and the bullet. 52 shots per gun can typically be done.

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Sidewall coring: A better version of the sidewall sampling, where a sample from the borehole wall is drilled out. That means that the structure of the rock is kept for future geological and petrophysical analyses.

2.1.3 Wireline Cased Hole Logging After the hole has been cased and a completion string is run for producing the well, some other logging tools may be run for monitoring purposes. These include: 

Thermal decay tool (TDT): They work like the neutron porosity tool but instead of measuring the HI they use the neutron capture cross-section, which principally depends on the amount of chlorine in the formation. The water saturation SW may be determined if the porosity and the formation salinity are known.

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Gamma ray spectroscopy tools (GST): It works on the same principle as the density tool, but the relative proportions of elements can be measured too. In particular, by achieving the relative amounts of carbon and oxygen, SW can be received (salinity independent).

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Production logging: With this tool flow contributions from various intervals in the formation are determined by using a spinner.

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Cement bond log: This tool is run to evaluate the quality of the cement bond between casing and formation. This is important because the quality of the cement bond affects the quality of other tools like the TDT or GST.

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Casing collar locator (CCL): It is run to identify the positions of casing collars and perforated intervals in a well. It shows the points where the thickness of the steel changes.

2.1.4 Pipe Conveyed Logging Where conventional wireline logging is not possible because of borehole deviation or doglegs, tools are typically run on drillpipe. After running the toolstring in the hole to a certain depth a special connector (called wet-connector) is pumped down to provide electrical contact to the toolstring by connects the cable to the tools. Then a side-entry sub (SES) is installed in the drillpipe, which allows the cable to pass from the inside of the pipe to the annulus. Then the toolstring can be run in farther to the deepest logging point. Pipe-conveyed logging is expensive because and for that only performed when acquire data via LWD is not possible. Nowadays most contractors offer a means to convert an operation to pipe-conveyed logging if a conventional wireline-toolstring got stuck in the hole. This is called “logging while fishing”.

2.2 Logging Contracts

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An oil company will typically set up contracts with more than one contractor for the provision of logging services to be sure to get good biddings. Elements that exist in common contracts include the following: 

Depth charge: The deepest depth a tool will be run in the hole.

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Survey charge: The interval where the particular tool is actually logging in the hole.

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Station charge: For tools like the formation pressure sampling tool and sidewall samples, this is a charge per station measurement. It has to be cleared what happens when such a charge may be dropped (e.g., if no useful data are recovered).

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Tool rental: Usually a daily charge for the tools to be on the rig, either on standby prior or during a logging job.

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Logging unit rental charge: Usually a monthly charge for a logging tool (winch, tool shed, computers) while it is on the rig.

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Base rental: Maybe a monthly charge for a couple of tools which have to be available for the client.

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Engineer charge: A day rate for a specialist, engineer or assistant present for a logging job. Newest technologies are often unavailable without somebody who takes care of it.

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In-hole charge: An hourly charge for some LWD contracts while tools are actually in the hole.

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Lost-in-hole charge: That any tools which are lost in the hole during operations can be replaced. Some contractors provide insurances for fixed sums to preserve companies of lost-in-hole charges.

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Cable splice charge: When tools get stuck in the hole and the wireline has to be cut.

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Processing charges: Where data require postprocessing, charges are usually applied in a similar way to survey charges.

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Data charges: Additional copies of log prints or data storage may require additional charges.

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Real-time data transmission charges: If the oil company, as usually, wants the data transmitted directly from the wellsite to the offices as digital data.

To incentive their contractor most oil companies discuss conditions to penalize the contractors for lost time or get bonuses for good safety performance. When the contractor has introduced new tools, which are not covered by the contract, and tests elements in the new tool, there should be a benefit for the contractor. Companies argue that the testing tool should be run for free, while the contractors argue that the company benefits of the new technological advantages. An arrangement could be that the new tool is run for the charge of the tool it replaces until its usefulness is proven and the charges rise. Typically the contractor wants the right for the acquired data for promotion of the tool. Decisions, how data has to be delivered to their offices and about quality control during logging, are specified by the oil companies either in the contract or in separate documents. These items usually include: 

Pre and post run tool calibration procedures

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Sampling increments

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Repeat sections to be performed

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Data items and format to be included in the log header

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Procedures for numbering and splicing different runs in a hole

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Scales to be used in the presentation of logs

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Format and media required for digital data

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Requirements of reporting of time breakdown of logging operations, personnel on site, serial numbers of tools used, inventory of explosives, and radioactive sources

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Specific safety procedures to be followed

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Provision of backup tools

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Fishing equipment to be provided

The more specified the requirements of the oil companies are, the better. Strict systems for controlling the logging operations and presentation of results lead to high-quality data and smooth operations.

2.3 Preparing a Logging Program The logging strategy should be developed at the FDP stage in a field development. Based on the type of well, decisions have to be made whether LWD or wireline and which types of tool to be run. Already during the exploration phase of a field data has to be available to be able to predict the reserves and develop a strategy. Lack of good-quality data can be very expensive, particularly for offshore wells, if too small or too big facilities are designed. Later in field life, particularly in times of production, data becomes much less, but is still used for updating the static model. Even in mature fields, because of extensions of accumulations have been discovered, data have to be locally revised. The strategy for data acquisition is determined by the FDP, and takes into account the relative uncertainties in the STOIIP (stock tank oil initially in place) and further development strategy. It is very important the there are discussions between petrophysicist and geologist about the need for coring and the analyses which have to be done when the core is recovered. In a well proposal the detailed requirements for logging operations is specified. These will be agreed on with other partners and the government and usually not be the exact models of tool, but show the general types for the different hole-sections. Typically it is not necessary to specify the SP log because it is usually run for free within the first toolstring in the hole. Thermometers are usually run as standard and the highest temperature is indicated in the log header. A program is usually sent to the rig for a logging job in each section, which includes: 

The actual mnemonics of tools to be run

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Intervals to be logged, if different from the total openhole action

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Which combination or tools is used to form the toolstring

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Data transmission/delivery requirements

For conventional logs (GR, resistivity, sonic, density, neutron…) it is not necessary to be very specific. Most companies will have established guidelines for the tool parameters. The type of resistivity tool will usually depend on the kind of mud (OBM or WBM) and the expected resistivity. Induction logs will be used in OBM, also in WBM, if the ratio of the mud filtrate resistivity (Rmf) to the water resistivity (RW) is higher than two, while laterologs tend to be more accurate in highly resistive formations ( resistivity at room temperature higher than 200 Ωm). The problem of induction tools is that they become saturated when used above 200 Ωm. Although definitely preferred in WBM, resistivity tools can also be used in OBM for formation imaging. In OBM it is necessary to use ultrasonic device.

2.4 Operational Decisions The logging program covers most eventualities during the logging job, but there are still situations, not everybody can be called to a meeting, and decisions have to be made on the rig. Things that are likely to happen and some decision considerations are listed below: Author: Markus Bernhart

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2.4.1 Tool failures Tools are usually being replaced by a backup and the job is continued. If special interval, particularly a reservoir interval, is to be measured and to ensure good-quality data, it can be useful to do more runs. However, the following situations may occur: 

When logging while drilling, it may be much more cost-effective to simply continue drilling at the end of a section if the data are not critical. The memory data may still be useable.

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If a wireline tool starts running erratically, it is not absolutely necessary to rerun it, because the data may be postprocessed if it is not critical.

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If advanced tools fail a backup tool is often not available on the rig. This problem can be solved by repairing the tool, get a backup tool sent from another location, or most commonly use an earlier version of the tool.

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For failures that lead to safety problems (e.g. explosive charges going off accidentally) operations are used to be suspended, until the cause for the event is cleared.

2.4.2 Stuck tools Either temporarily or permanently, tools get stuck in the hole fairly regularly. Often bad hole conditions are indicated, but this will be considered in logging program adjustments. The time a hole is kept open, the more bad the problems might become. There are three sorts of sticking: 

Differential sticking

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Key seating

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Holding up

Differential sticking means that either the cable or the toolstring gets embedded in the wall of the borehole and is held in place because of the different pressures of mud and formation. Then a procedure of pull and slack is started and after about 30 minutes of cycling the moveability should be back. The pulling is done with up to 90% of the weakpoint of the cable (the point at which cable and tool get separate ways). Key seating occurs when a groove is cut into one side of the borehole, with the consequence that the cable can still be pulled upwards but not the toolstring. This often means that the force of pulling exceeds the weakpoint of the cable and the toolstring drops down and is hard to be recovered, or might be damaged. Holding up occurs, when constriction, blockage, doglegs or shelf occurs in the borehole so that the toolstring can not be moved downwards. In such a case the toolstring is retrieved to the surface and its length is made either shorter or in some cases longer. If a tool can’t be recovered anymore, there are two procedures: cutting-and-threading (the cable is cut at the surface) or breaking the weakpoint (accidentally or on purpose). Most oil companies will specify that they don’t want to break the weakpoint on purpose even if the other procedure costs much more time. In the situation of using nuclear sources this is particularly true because the tools have to be recovered undamaged. But it also can happen that nuclear sources are lost irretrievably and then there are special procedures to be followed, which include notification of government bodies and avoiding any nuclear contamination.

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2.5 Coring 2.5.1 Core Acquisition Coring is an important source of gaining additional information about the reservoir not obtainable by logs and a mean to calibrate the petrophysical model during the exploration phase of a field. The decisions for time and place of coring will be made by the operational department in corporation with the geologist, taking into account the data requirements and the cost of the operations. Usually at least a core is get out of the main reservoir during exploration and the appraisal phase of drilling. A conventional core will be 18 meters long and four inch in diameter. After drilling it, a barrel with an outer diameter of 6 ¾ in. will be used to transport it to the surface, where it is recovered and separated into pieces of 3 feet length. Later the parts of the core will be brought to a core laboratory. To improve the quality of the core special techniques may be used, which include: 

Using a larger core diameter (5 in)

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Using a sleeve of aluminium or fibreglass which is cut into sections to safe the core of breaking into smaller parts, because the core doesn’t leave the sleeve

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Sponge coring, what means that formation fluids are absorbed by a polyurethane material which surrounds the core in the sleeve

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Resin coring, where a special resin is used at the surface of the core to seal the fluids inside

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Freezing the core as soon as it reaches the surface, also not to lose the fluids inside

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Cutting plugs from the core at the wellsite and sealing these to get information about the formation fluids

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Using tracers in the mud to attempt to quantify the extent of invasion of drilling mud.

If assumed that the in-situ fluids represent the formation fluids, the following techniques may be applied: 

Centrifuging of samples to get formation water out, which is then analysed chemically and electrically

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Use Dean-Stark analysis to determine the amounts of water and hydrocarbons, and to measure SW

2.5.2 Conventional Core Analysis After drilling, sections of the core are sealed (usually 0.5m every 10 min) and kept as preserved samples. The remaining part of the core is then cleaned, slabbed, laid out and visually inspected by the geologist and the petrophysicist. Important information a petrophysicist can get by such an inspection are: 

The homogeneity of the reservoir and further information about variation, not determined by the logging tools

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The type of cementation and distribution of porosity and permeability, including presence of fractures (either natural, cemented, or drilling induced) and their orientation.

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The presence of hydrocarbons by smelling or under ultraviolet light (UV)

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The types of minerals present

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Dip features that may influence the logging results

Usually plugs of a diameter of 0.5 in are cut at regular intervals after slabbing. These are then cleaned by refluxing with a solvent for 24 hours and dried at a temperature that will remove any water. With the

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plugs, the porosity (using a helium porosimeter), horizontal permeability and grain density is measured. To determine the vertical permeability, some other plugs have to be cut in the axis of the core. Normally a reference log, which can be put in correlation to the wireline data, is made by running a gamma ray detector or density-type device over the whole core. When the depths of the core and the log are different, it is necessary to shift the data before it can be compared. Also the pressure at which the core is measured will not be the same as in the formation and so it has to be corrected with a factor that is determined by further special core analysis (SCAL).

2.5.3 Special Core Analysis SCAL measurements are typically done on a set of larger diameter plugs (1.5in). These may either be cut at regular increments or the petrophysicist may decide certain depth of interest. It is most important to get a broad spectrum of properties which reflect the range of properties seen in the reservoir. The homogeneity of the SCAL plugs has to be checked by using computed axial tomography (CAT). The number of plugs needed for a typical program is hard to say because it depends on the reservoir type, thickness and homogeneity. In general such a SCAL program may use between five and 50 plugs. Some measurements directly relevant to the petrophysical model follow: 

Porosity and permeability at overburden conditions. Here it is important to state the pressures at which the measurements are done. Typically the measurements are performed at five different pressures, which are expected during the depletion of the reservoir.



Cementation exponent (m). Plugs, 100 % saturated with brine representative for the formation salinity are measured for resistivity. This is usually done at ambient conditions but may also be performed at in-situ pressure.



Saturation exponent (n). The resistivity of the plugs as a function of SW, with the resistivity fluid either being air or kerosene, typically measured at ambient conditions.



Capillary pressure (Pc). The saturation of a nonwetting fluid (air, mercury, or kerosene) is measured as a function of an applied Pc. The brine is steadily replaced by the nonwetting fluid in a drainage cycle. In the next step, an imbibition cycle, brine is reintroduced to replace the nonwetting phase.

These measurements can be done by different techniques. Traditionally m, n, Pc would be measured using the porous plate method, with air as the nonwetting phase. But this procedure is limited to a pressure of 100 psi, so other Pc measurements will be performed using mercury injection up to 60,000 psi and thereby also determining the pore-size distribution. There are some reasons why many oil companies no longer favour these techniques: 

Using mercury leads to a destruction of the plugs and is a potential source of danger concerning environment and health.



Measurements including air or mercury are not representative of true reservoir conditions and may give misleading results.



Additional to the ineffectiveness in time of the porous plate technique, results are inaccurate if grain loss occurs, and the electrical measurements tend to be operator dependant.

Preferred techniques to avoid these problems are following: 

Measuring of m and n should be done by using a continuous injection apparatus. The procedure the sample has to be mounted vertically, flushed with brine, then kerosene is injected at a continuous rate, while resistivity and saturation are monitored continually.



The capillary pressure should be measured using a centrifuge capable of a pressure up to 200psi. The plug is flushed with brine and then rotated at different rotational speeds equivalent to different pressures), while the amount of exiting fluid is monitored. An additional advantage of this technique is that the sample is not handled during the procedure.

Author: Markus Bernhart

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Well Logging

2.5.4 Limitations of core measurements Petrophysicists tend to treat measurements made on cores as completely true for the reservoir parameters, but some reasons, that explain why this is not always the case follow: 

A core is only a small part of rock, taken from a very point of the formation and there is no priori reason why it should be representative for the whole reservoir.



Stress and temperature changes coming from coring and recovery process may affect the structure of the rock.



The plugging, cleaning and drying process may completely change the wettability of a plug, making it unrepresentative of downhole conditions.



Measurements of resistivity with air as the nonwetting phase may highly differ from the real value for reservoir conditions. Brine has a totally different resistivity at ambient temperature. Experiments have shown that the values of m and n measured under real in-situ conditions differ completely from those under ambient conditions.



When measuring m, n, and Pc on lets say 10 plugs, it can easily happen that the results will show us 10 different values. It is the question, if 10 plugs can ever be representative for a reservoir of thousands of acre-feet.

Although core-derived data should never be treated as completely reliable, using data of cores will be better than having nothing at all.

2.6 Wellsite mud logging There are two main responsibilities for typically heaving a mud-logging unit present on the rig during the drilling of a well, which include: 

Monitoring the drilling parameters and gas/liquid/solids that return from the well to help the drilling department to increase safety and optimize the drilling process



Providing information that can be used for evaluation purposes

Usually a daily mud log will be sent to the oil company office which includes information about gas readings, a check for poisonous gases (H2S, SO2), a report of received cuttings, rate of penetration (ROP) and hydrocarbon indications in samples. Mud logs can be of great use for petrophysicist and geologist in operational decision making and evaluation. They are also important for identification of the lithology, formation type, porous and permeable zones, and picking of depth for coring and casing. From time to time samples of cuttings are taken from the shale shakers, typically in periods of about five minutes, not to miss any changes in the formation. These samples are then either sealed as “wet samples” or as “dry samples” (washed, dried) and retained. Washed ones are examined under the microscope in the mud logging unit, so that important information can be sent to the oil companies’ office. For usefulness of this information some reporting standards have to be laid down. Items that should be included are: 

Grain properties o

Texture (muddy/composite)

o

Type (pelletoid/micropelletoid)

Author: Markus Bernhart

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



o

Colour

o

Roundness or sphericity

o

Sorting

o

Hardness

o

Size

o

Additional trace minerals (e.g. pyrite, calcite, dolomite, siderite)

o

Carbonate particle types

o

Skeletal particles (fossils, foraminifera)

o

Nonskeletal particles lithoclasts, aggregates, rounded particles)

o

Coated particles

Porosity and permeability o

Porosity type (intergranular, fracture, vuggy)

o

Permeability (qualitative as tight, slightly or highly permeable)

Hydrocarbon detection

The detection of hydrocarbons may be done by using the following procedures: 

Natural fluorescence. In this method the property of oil is used, that it fluoresces under the UV light. But you can’t be sure that the fluorescent material is moveable oil because there are some other: OBM or lubricants used, other sources of carbon (dead oil or bitumen), gilsonite cement



Solvent cut. In this procedure about 3 cm of dried and crushed sample is placed in a test tube and solvent (typically chlorothen, ether, and chloroform, all of them toxic and flammable and so to be handled carefully) is added to about 1 cm above the sample. After shaking the test tube for a few minutes the change of colour is measured. This colour change is the solvent cut. Heavy oil (e.g. asphalts) generally has a stronger cut than lighter oil (e.g. paraffins). Additionally the test tube may be put under the UV light and the results compared with these of the pure solvent, to check if any fluorescence is present.



Acetone test. A sample of washed, dried and crushed cuttings is put in a test tube together with acetone. This tube is shaken and afterwards the acetone is filtered into another tube, to which the same amount of water is added. By the reason that acetone is dissolvable in water, but hydrocarbons are not the water becomes milky in colour. This test is useful where only light oil or condensate is present.



Visible staining. If the permeability and/or viscosity is poor, oil may remain in cuttings and be visible under the microscope as a form of stain on the surface of the cuttings.



Odour. During the cleaning and drying process the characteristic smell of oil may be discerned.



Gas detection analysis. This works by passing air, drawn from the bell nipple (the point where the mud reaches the surface) over a detector filament. By inducing different voltages, which leads to combustion of components of different weight in the gas (at lower voltages the lower components burn, at higher voltages all the burnable parts), followed by a rising of temperature and finally to changes in resistance of the filament, what can be measured. In this way the proportions of the various components can be estimated.

Author: Markus Bernhart

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3. Quicklook log interpretation When the total depth (TD) of a well has been reached, an interpretation of the openhole logs will be done by the petrophysicist. Before starting his interpretation he needs: 

All the relevant daily drilling reports (including latest deviation, last casing depth and mud data)



All the latest mud log information (including description of the cuttings, gas reading, shows, and rate of penetration)



Logs and interpretations of other wells penetrating the same formation (m, n, Rw, rhog, fluid contacts)



Copy of contractor’s chart book

3.1 Basic quality control The petrophysicist has to ensure that the quality of the log data after getting them. He should perform the following points: 

Control if the logger’s total depth and last casing shoe depths roughly matches those of the last drilling reports.



Check if derrick floor elevation and ground level positions are correct.



Log curves have to be on depth with each other. Zones of temporarily sticking can be determined using the tension curve. These Zones will put the curves off depth and result in “flatlining”.



Check that the caliper reads correctly inside the casing for measuring true values for the inner diameter (ID) and that measurement is done in nonpermeable zones which are not washed out.



Check the density borehole correction curve. For clearly washed out sections (>18 inch in diameter) the density curve will be unusable in most cases.



Look at the resistivity curves. If OBM is used, shallow curves will typically read higher values than deeper curves, except in highly oil or gas saturated zones. Using WBM leads to lower readings of shallow curves, providing Rmf < Rw, or in hydrocarbon bearing zones. Theoretically the curves overlie each other in nonpermeable zones such as shales. Practically anisotropy or shoulder-bed effects often lead to divergence.



Check if the sonic log shows a transit time of 47μs/ft in the casing.



Watch out for any cycle-type behaviour in any of the curves. This may cause an irregular borehole shape.



Check that acceptable industry norms are used for the presentation scales. These are generally: o

GR: 0 – 50 API

o

Caliper: 8 - 18”

o

Resistivity: 0.2 – 2000 Ωm on log scale

o

Density: 1.95 – 2.95 g/cm3 (solid line)

o

Neutron: -0.15 ± 0.45 (porosity fraction) (dashed line)

o

Sonic: 140 – 40 μs/ft

Author: Markus Bernhart

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3.2 Identifying the reservoir The behaviour of density and neutron logs will be the most reliable indicator of reservoir rock, with the density moving to the left (lower density) and touching or crossing the neutron curve. This will in most cases lead to a fall of the gamma ray log in clastic reservoirs. In some reservoirs the gamma ray is not a reliable indicator of sands, due to the presence in sands of radioactive minerals. Zones of high density (typically 6 or more neutron porosity units) can easily be determined as shales. The quality of a reservoir increases with the size of the crossover between density and neutron logs. However, for the same porosity, zones of gas have a greater crossover the zones of oil or water, because both the neutron and density logs are determined statistically. They will wiggle even in completely homogeneous formations. Therefore it is dangerous to say there is net sand if there is a crossover. For most reservoirs the following approach is safer: 

Take an average reading for the gamma ray in clean sands (GRsa) and for shales (GRsh) better the mode than the highest reading.



Calculate the volume of shale as: Vsh = (GR – GRsa) / (GRsh – GRsa) Then determine a value of Vsh to use as a cut-off, by comparing Vsh with the density and neutron log. Typically 50% is used.

If you can’t use the gamma ray as a sand indicator in a special case, use the entire gross as being net sand and apply a porosity cut-off at a later stage.

7 Identifying net reservoir

Author: Markus Bernhart

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Well Logging

3.3 Identifying the fluid type and contacts The porosity calculation depends on the formation fluid type. Therefore you should have a working assumption regarding the fluids at this stage. If there is information available from other wells in the same region, you can take the depth of gas/oil or oil/water contact, convert sub sea depths into measured depth and mark it on your logs. If the pressures have already been determined, what is usually never the case, any information on possible free water levels (FWLs) or GOCs can be marked on the logs too. For any evidence of hydrocarbons, start with comparing the density and deepest reading resistivity log. In the clastic response, resistivity and density will follow each other to the left and to the right in water sands; they will be a mirror image of each other in hydrocarbon sands. Not all of the hydrocarbon and water zones will show their typical behaviour. Reasons for this can be: 

In the case of very high formation-water salinity, the resistivity may also drop in clean sands.



A rise of the resistivity may be missing, if shaly sand zones have a high proportion of conductive dispersed shales.



If there are thinly laminated sands between shales, the deep resistivity may not be able to “see” the sands and the value may fail to rise.



If drilling has been done very heavy overbalanced, the mud may have entered the formation so deep that the invaded zone completely prevents a deeper look into the formation.



Very fresh formation water (high Rw) may also lead to wrong results for resistivity, in water bearing formation.

8 Identifying net pay

Author: Markus Bernhart

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9 Identifying gas sands from Vp/Vs versus Vp plot

When one of the first two situations occurs, you have to look at the absolute value of the deep resistivity, but not only at the behaviour compared with the density. When water sand has been penetrated in the well, somebody should know about resistivity of water-bearing sand. If the measured resistivity is higher than the one of the water bearing sand, the presence of hydrocarbons can be expected. When it is not clear if there are hydrocarbons in the formation, any mud log data should be examined. You should not always expect that mud logging gives an answer to the question if there are hydrocarbons or not, particularly if the sands are thin and the overbalance is high. Moreover, some minor gas peaks may be observed even in sand that is water bearing. Any GOC can very easily be determined on the log in very clean porous sands. However, practically GOCs will only be determined correctly in about 50% of the cases. Secondary gas caps, which appear in depleted reservoirs, are typically not picked up in this way. A more reliable way to identify GOCs formation-pressure plots, but these will only be useful in virgin reservoirs. In the past there have many cross plots been proposed to identify gas caps, including neutron, density, sonic, and gamma ray logs, but they are not really reliable. In completed reservoirs where gas has started to come out of solution in an oil zone, but had no chance to equilibrate (form a gas cap), the gas may only form football-sized pockets in between the oil. In this situation the basic logs will give no satisfactory answer.

10 Selection of the fluid density for porosity calculation, using a density tool

Author: Markus Bernhart

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Well Logging

3.4 Calculating the porosity The porosity should be determined from the density log, using the following equation: Φ = (rhom – density) / (rhom – rhof) where rhom is the matrix density (in g/cm3) and rhof the density of the fluid (in g/cm3).

The density tool injects gamma rays into the formation, which are then scattered by the electrons in the formation, a process known as Compton scattering. Two detectors then detect these gamma rays. By the fact that the tool measures electron density, there will be a little miscalibration due to the variation in electron density between different materials. The correction is typically small (1% or less) and so no major cause for concern. The density porosity will at some stage be calibrated against core data, so for Quicklook purposes the correction can be ignored. The rhom value for sandstone lies somewhere between 2.65 and 2.67 g/cm3. If core data is available, the value can be taken from the average measured on core plugs. The fluid density depends on the mud type, formation fluid properties and extent of invasion seen by the density log. For information about the accuracy of the values, following tests may be applied: 

If information about other wells in the same region is available, the average zonal porosities may be compared.



Across any contact there should be no jump in porosity, except for diagenetic OWC occurring.



Porosities of sandstone will not be expected to exceed 36%.

By using the density log the total porosity is calculated, including water bound to clays or held in clay porosity. The advantage is that these porosities can directly be compared with the ones measured on plugs, when there is all clay-bound and free water removed. You have to check for washed-out zones, which can result in high density values and unrealistically high porosities. In same cases it is enough to set a value limit. Zones often wash out because they are soft and have a high porosity. In water bearing zones the true resistivity (Rt) and the Archie equation Rt = Rw * Φ-m * Sw-n or Sw = [(Rt / Rw) * Φm]-1/n may be used to get a good estimate of the porosity. The effective porosity is the total porosity minus the clay bound water and the water held in clay porosity. It may be defined as: Φeff = Φtotal * (1 – C * Vsh) where the factor C depends on the shale porosity and the cation exchange capacity (CEC). It may be determined by calculating the total porosity in pure shales (Vsh = 1) and setting Φeff to zero. But it’s not sure that taking the properties of non-reservoir zones, for shales within sands in the reservoir, leads to correct results. Some people mean that calculating Φeff should not be part of a Quicklook interpretation, and using a neutron density crossplot is not the best way to determine porosities in sandstone. You should use the neutron log for only two things 

Qualitative identification (using the density) of shale/sand zones



Identification of gas zones

They do also not favour the use of the sonic log for porosity determination under any circumstances.

Author: Markus Bernhart

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Well Logging

3.5 Calculating hydrocarbon saturation For calculating saturations of clastic reservoirs by Quicklook evaluations, it is in most cases sufficient to take the deepest reading resistivity tool directly as Rt and put it into the Archie equation. If there are no regional core values available it’s recommended to put m = n = 2. Rw is the parameter to be determined when m and n are predefined. The best way to do this issue is a Pickett plot over a known water bearing section of the formation. By plotting log(Rt) versus log(Φ), m may be determined from the gradient of the line drawn through the points and Rw may be read from the intercept of the line with the Rt axis. If m is fixed, the line can be shifted only up and down. If the slope doesn’t correspond with the assumed m value, changing m within a reasonable range (1.5 – 2.5) is recommended. Also values for Rw may be available from nearby wells, but will usually be expressed as NaCl concentration [ppm or mg/l] and has therefore to be converted using the contractor’s chart book and knowledge of the formation temperature. In the case that no clear water section has been logged in the well, regional data has to be used, although the Pickett plot may give other results than expected because of regional information. That can have the following reasons: 

Porosities calculated in the well are not correct



100% water bearing is assumed, but not really the case



m needs to be adjusted



Regional data doesn’t suit to the well

This last point can have as reason: 

Different salinities in the wells



The chart book may assume that Rw is influenced by the conductivity of brine only coming from the presence of NaCl. But there can also be other chlorides (e.g. MgCl).



The water zone may originally have been an oil bearing zone, but became flushed by injection (seawater is often used for injection offshore)



Other problems caused by the treatment of samples

11 Pickett Plot

Author: Markus Bernhart

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Well Logging

In theory there is a procedure using the spontaneous potential curve to derive a measurement of Rw, which functions the following way: 1. Draw a shale baseline on the SP log, which defines an average of the SP readings in 100% shale zones 2. Determine the maximum Sp deflection observed in thick porous parts of the reservoir 3. To correct for invasion, borehole, and bed effects, use the appropriate chart supplied by the contractor and convert the SP deflection to a static spontaneous potential (SSP) 4. By taking use of the appropriate chart, determine the kinetic energy (Ek), and the mud cake contribution (mc) 5. Get Ek, shale using Ek, and shale (= ΔP[bar] / 6.9, where ΔP is the difference between mud pressure and formation pressure) 6. Calculate the Eckert number (Ec) at BHT in °C: Ec(BHT) = SSP + Ek, mc - Eksh 7. A correction of Ec(BHT) to the standard temperature has to be done Ec(25°C) = Ec(BHT) *298 / (273 + BHT) 8. Get the mud filtrate salinity by using Rmf and temperature 9. Determine Qvshale using the contractor’s charts or else set Qvshale = 4 mmol/cm3 10. Determine the formation water salinity by taking use of the appropriate chart( Ec(25°C) ), the mud salinity and Qvshale 11. Reconvert the formation water salinity to the bottom hole temperature After all it is essential that the used model calculates 100% water in known water bearing reservoirs. Otherwise, the calculated Sw will not be correct.

3.6 Presenting the results After porosity and water saturations are calculated, it is usually required to provide averages over formation zones. First define the depths for which the results should be broken up, taking into account changes in fluid type, poor quality zones, or any point of change in log character. Then a table should be produced. The average porosity is given by: Φ(average) = ΣΦi / h, where h is the net thickness The average value of Sw is calculated with: Sw(average) = ΣΦi * Swi / ΣΦi For zones of permeability transformation, an average permeability for each major sand body should be presented. Usually the net is defined on the basis of a Vsh cut-off, but when this is not possible, a porosity cut-off can be used. The cut-off point should be set at a value equivalent to a permeability of 1 millidarcy (md) for sections of oil and 0.1 md for gas zones. Using cut-offs is not always a good solution, although they will be necessary if Archie’s equation gives nonzero hydrocarbon saturations in completely nonreservoir shales. In practise the zones worth to be perforated are chosen in assistance of a 1:200 print of the evaluated logs. For presentation purposes the use of a 1:500 version of the evaluated logs, including all the possible data, is useful. Although it is different from company to company, it is common to use red for oil, green for gas, blue for water and yellow for unidentified hydrocarbons.

Author: Markus Bernhart

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12 A report of the evaluated results

Adding a curve called SHPOR, derived from (1 – Sw) * Φ, and shading from zero to the curve with the appropriate colour, is recommended. This curve helps to represent the total volume of the fluid. Thin zones with higher porosity should be put more attention on, as thicker zones of lower porosity.

3.7 Pressure/sampling A requirement to run the pressure/sampling tool to acquire pretests and possibly downhole samples will be given in most cases. These data can be really valuable to the petrophysicist in determining which fluids are present in the formation, and are also used by the reservoir engineer and production technologist. Pretests can give the following information: 

Depths of any free water levels and gas oil contacts in the well



In-situ fluid densities of the oil, gas, and water legs



Absolute values for aquifer and formation pressure



Qualitative mobility and permeability indications



Bottomhole pressure and temperature in the wellbore

Additional downhole samples can provide the following information: 

Pressure/volume/temperature (PVT) properties of oil and gas in the reservoir



Formation-water salinity



More information about mobility/permeability

Typically a probe is mechanically forced into the formation and chambers are opened in the tool where the formation flows in. For pretests small chambers of only a few cubic centimetres are used, which can be emptied before the next pretest station. In downhole sampling, larger chambers of 2 ¾ or 6 gallons are used, because the first fluids, entering, may be contaminated by mud filtrate. In the typical procedure two chambers are used. The one that is filled first should contain all the contaminated fluid, and then the second one is filled with hopefully only representative fluid of the formation. After retrieving the samples at the surface, they can either be drained on the well site, or kept sealed while bringing them to the PVT laboratory. Pretests and sampling are often not successful. By leaving the tool in the borehole, the problem of getting stuck can occur by one of the following reasons:

Author: Markus Bernhart

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Well Logging



Seal failure. Around the probe a rubber pad is placed, which provides a seal between the mud pressure and the formation pressure. This pad may fail, resulting in a rapid pressure build-up in the mud.



Supercharging. Some higher pressure occurring during the drilling process may be retained by tight sections of the formation. For pretests anomalously high pressures are measured.



Dry test. In very tight formations the pressure is very slowly built up in the chambers and it is not used to wail till equilibrium is reached.



Anomalous gradients. Sands may lie on different pressure trends when they have been isolated even over geological time scales and not share a common aquifer of FWL. Gradients may also not be meaningful, when any depletion has occurred in the reservoir or it is not in a true equilibrium state (slowly leaking seal or fault).

Now it will be useful to know how to distinguish between free water level (FWL), free oil level (FOL), oil water contact (OWC), gas water contact (GWC) and gas oil contact (GOC), and in which relation they are in pressure measurements. At the FWL of a reservoir, the capillary pressure Pc is zero and below it, no hydrocarbons are in that pressure system. The intersection of the oil and water, or gas and water points will fall on the FWL on the pressure-depth-plot. Above the FWL, water may be drained by hydrocarbons. But particularly in low permeable rocks, a certain entry pressure has to be given to get Sw under a certain unity. When such a pressure is reached, hydrocarbons will be found in the rock and the OWC or GWC is crossed. Between FWL and OWC or GWC, pressure points will continue to fall on a waterline. The pressure will be above the OWC for a gas or oil reservoir, following a trend corresponding to an oil gradient (but intersecting the waterline at the FWL). For the GOC the situation is not the same as for the OWC, because there are three phases (water, oil, gas) instead of two. The GOC is commonly treated as being the intersection of the gas and oil pressure lines, what is technically incorrect, but causes no problems. For a pure gas reservoir, the pressure will rise above the GWC on a trend corresponding to a gas gradient (intersecting the waterline at the FWL). Remind that these considerations have nothing to do with the “transition zone”. In reservoirs changing in quality, the OWC and GWC may vary in depth across the field, by the reason that poor-quality rocks may show the effect of entry height, which can reach tens of meters.

13 Formation pressure plot

Author: Markus Bernhart

Page: 27

Well Logging

3.8 Permeability determination Like in a production test, the behaviour of the pressure build-up may be used to estimate the properties of the formation. The mobility M of the formation is defined by: M=k/μ where k is the permeability [md] of the formation, and μ the viscosity [cp] of the fluid that enters the chamber. Theoretically M is related to the drawdown pressure, drawdown time and the flow rate. The contractor usually makes mobility estimation by using the analysis of the build-up. With known viscosity, the mobility can be converted to the permeability. Usually the pretest chamber is filled with either water or oil-based mud filtrate. Some values are given in figure 11. The information received by pretests is whether some permeability is present if a good build-up is obtained, but it will only be a point measurement. In fact, by just moving the probe a few centimetres up or down, the results for mobility may become completely different ones. With a bit of bad luck, the place where the probe is taken from doesn’t give a good build-up. Additionally, the permeability of a zone may not be represented. Practically pretests should only be used for determining if there is any porosity, but for achieving values to use in dynamic models, other methods are used. Formation damage occurring while drilling, may lead to too low pretest permeability, compared with a poroperm relationship. The same may happen, when the zone is tested for production. The contractor should always hand the actual field prints to the petrophysicist, to allow him to have a look at the estimated permeability and fluid contacts. Reasons for this are: 

Older tools may use other units (psig, what means psi per gauge, instead of absolute psi, psia). If the wrong-unit-values are entered into the database, this will lead to a shift equivalent to atmospheric pressure (14.7 psi).



Sometimes not all the field data are entered into the database when a field is created, such as data of “tight zones”. But it is crucial to know about that.



When there is no data for such a tight zone, an estimation of formation pressure may be made by extrapolating the build-up pressures.



There will typically be a measured depth for the pretest and a true vertical depth, referenced to the derrick floor, be given. It is very important to check, if the pressures are referenced properly to the best estimate of true vertical depth relative to the datum (usually mean sea level). Usually a gyro survey is run after the final casing has been set, to convert all measured depths to TVD relative to the datum, after the pressure tool is run.

The quick look interpretations presented in this chapter will suffice for operational decisions on the well. The evaluated logs are usually presented at scales of 1: 200 and 1: 500 with the sums and averages marked on the logs, and the pore fluids represented by their colours.

14 Typical viscosities of borehole fluids

Author: Markus Bernhart

Page: 28

Well Logging

15 Typical behaviour of the pressure during a pretest

Author: Markus Bernhart

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Well Logging

4. Full interpretation When the final data and prints are available, the digital data should be stored within a corporate database. At the stage the petrophysicist is used to do a full interpretation, which can still be revised, when further core analysis or information from offset wells become available. In some cases the only thing to do is to refine the conventional Archie interpretation, while in other cases this rapid interpretation may be completely laid aside in favour of a more advanced model. The ways the Archie model may be refined will be discussed in this chapter.

4.1 Net sand definition The petrophysicist should visit the core laboratory as soon as core data has been acquired, to investigate the slabbed core. He has to check that there hasn’t happened any wrong interpretation. Core that can be easily determined as reservoir rock, the exact net sand footage should be measured with, to be able to check some measured values against the calculations made on the logs. Therefore the shale volume may be varied. Additionally photographs of the cores are taken, either under normal and UV light, which assist in the determination of net reservoir. After the conventional core analysis measurements of core porosity, grain density, and permeability will be done. If measurements happened at overburden conditions, the results have to be converted to in-situ conditions, using conversion factors. If these are not available, regional data will help to assume some, while true ones are calculated out of core analysis. Commonly the in-situ porosity versus logarithm of permeability is plotted, if necessary divided into sections, so that a single line can be fitted to the data with reasonable accuracy. As the result we get the so called poroperm relationship, which is typically of the form: k = 10^ (ka + kb * Φ) Where k is the permeability of the reservoir, and typical values for ka and kb are -2 and 20. The sands of the chosen Vsh cut-off should show no porosities corresponding to 1md in oil zones and 0.1 md in gas zones. If this is not the case, an additional cut-off will be necessary, to check if a tight zone has been investigated. When having no core data, it is useful to plot the gamma ray versus the density log to find the best point to distinguish between net and non-net from the gamma ray.

16 Determination of reservoir cut-offs by using a GR-density cross plot

Author: Markus Bernhart

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Shale becomes dispersed in pore space (increasing GR) and now the density increases until the point is reached, where no more pore space is available for free fluids. Beyond this point shale becomes still more and finally reaches 100% of the formation, but during this process the density changes only slightly (difference between densities of quartz and shale is small). The correct cut-off is therefore the point at which the gradient changes, corresponding to zero effective porosity. The GR will not be the only source needed to get Vsh if radioactive minerals are present in the sands. In such a situation only a porosity cut-off may be used. If thin laminated sands are thought to be nonreservoir by using a Vsh or porosity cut-off, no cut-offs should be used at all. Because the Archie approach gives no satisfactory results any more, advanced techniques have to be used.

4.2 Porosity calculation In most cases the density porosity should be determined, by using a fluid with an appropriate density. The conventional core analysis helps to calibrate it, before correcting it to in-situ conditions. Core data and calculated porosity have to be shifted so they match and are plotted together. With the core grain density measurements a histogram should be made, which can be used to determine the appropriate value to use in the sands. This histogram should indication of the possible spread of values, and the mean grain density. Therefore plugs taken from clearly non-reservoir formation must not be used. Then a cross plot of the log density against the in-situ core porosity values is made. The density should be equivalent to the core grain density at zero core porosity, while for a unit core porosity the core porosity is used to be equivalent to the fluid density. The usual procedure is to place an appropriate line in between the data points and then extrapolate the line to the unity porosity to get an appropriate fluid density. For any gas/oil/water zone this has to be done separately. Theoretically the results should be almost the same as the assumed ones of the quick look analysis. Differences can occur because of: 

Miscalibration of the density log

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Mud chemicals (e.g. barite) may effect the density log

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Higher or lower amount of invasion as assumed

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Problems with core plug measurement or during conversion to in-situ conditions

Where anomalous fluid densities are determined, they will commonly only be used for the current well and possibly only for the cored zone, while densities which agree with the expected values will be used for other wells with comparable parameters too.

17 Porosity calibrated by a core

Author: Markus Bernhart

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4.3 Archie saturation Cementation (m) and saturation (n) exponents measured in special core analysis (SCAL) can be included into the Archie model. For determining m, the resistivity of a plug flushed with brine, having the expected salinity of the reservoir, is measured. The logarithm of formation factor, given by log(F) = log(R0/Rw), is plotted against log(porosity), what looks similar to the Archie model: log(F) = -m * log(Φ) Here m is given by the gradient of line. Remember, the higher the value for m, the higher the calculated water saturation Sw and the other way around. In n measurements the plugs are desaturated (with either air or kerosene) after being flushed with brine. By performing this way, the true resistivity Rt can be measured and plotted versus Sw. Here a resemblance to the Archie model can be watched too, by plotting the logarithm of the resistivity index given by log(I) = log(Rt/R0) versus log(Sw): log(I) = -n * log(Sw) In this procedure the gradient of the line gives n. The higher the n value, the higher the calculated Sw and vice versa. Anomalously high n values (higher than 2.5) may indicate a mixed or oil-wet system, for that further investigation is needed. Low n values typically belong to good-quality water-wet permeable rock. From the time on, m and n are set, the value for Rw, which might be required to calculate Sw = 100% in known water sands, can not be completely free chosen. If formation water salinity has been determined by produced water samples, an issue can be to choose whether to trust m or Rw. But the problem of not knowing what to use can also depend on an error in the porosity calculation. However, it should always be checked if the values for cementation exponent are reliable. If measurements come from oil legs instead of water legs, it is possible that the values are not representative for the reservoir because of diagenetic effects. Further should be checked if either invasion or shoulder bed effects are significantly influencing the deepest reading resistivity tool. For a well drilled with oil based mud includes thick sand. Whatsoever, the deep resistivity tool should be used as it is. But if there really are effects of invasion or shoulders, it is better to use a saturation/height approach instead of an Archie model. In the case that one wants to go on with correcting the resistivity, he may use the contractor’s chart book or computer based algorithms.

4.4 Permeability The final evaluation of the static and dynamic model makes it necessary to use a permeability log as well as zonal averages for input. To get a permeability log out of the data of a porosity log, the poroperm relationship may be used. When the log is finished, it will be necessary to check if there are any sections of anomalously high values. Common sandstones do not exceed about 1500md, although top-quality sands with porosities above 35% may have permeabilities up to about 4000md. If necessary, do a cut-off at a value corresponding to the core data. Permeabilities of non-reservoir zones should be set to a very low value (e.g. 0.001md). Permeabilities calculated using different sources (nuclear magnetic resonance NMR, formation pressure tool, and production tests) should give roughly the same results. There are three types for making zonal averages of the permeability, which are: 

The arithmetic average, that is calculated as follows: karith = Σ ki * hi / Σ hi where hi is the space between the different places of measurements. This average can be used if the flow in the reservoir is in the direction of the bedding plane. Small impermeable streaks affect the average very little.



The geometric average is given by:

Author: Markus Bernhart

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Kgeom = exp(Σ log(ki) * hi / Σ hi) This average is used where parts of the flow are directed as the bedding plane and parts normal to it. Impermeable streaks may have some influence on the calculated average, but not make it useless. 

The harmonic average is determined with: kharm = 1 / (Σ (hi / ki) / Σ hi) This average is used in the case of the flow being normal to the direction of the bedding plane. The values will be completely dominated by impermeable streaks.

In horizontal wells it comes to another effect, due to the fact that kv / kh in the microscopic scale is usually less than one. This effect may be estimated as follows. Let α be equal kv / kh, where kv is the vertical permeability and kh the horizontal one. The average permeability, which is influenced either of the vertical and the horizontal part, is given by: kav = kh * (1 + α) / 2 The typical procedure is to assume the parameters of kv and kh over an entire reservoir within a dynamic model. Typical values for kv / kh are between 0.1 and 0.3. But even if the formation appears completely homogenous, the permeabilities, determined in a poroperm relationship, need to be adjusted for a horizontal well.

18 Effect of kv / kh < 1 in horizontal wells on the permeability

For the print of zonal averages, it is common to add the product k * h, where h is the thickness of the zone and can be related to the flow, generated in a production test. Arithmetic averages will often be higher than those yielding from a production test. This can have the following reasons:

Author: Markus Bernhart

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

The flow doesn’t run through the entire perforated zone, what results in a smaller value of h, than the one assumed in the petrophysical calculation.

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Some of the flow deviates from the direction of the bedding plane.

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After the Openhole logging, but still before the testing operation, some formation damage (called skin) has occurred.

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The in-situ brine permeability, calibrated in the laboratory may be inappropriate, because of relative permeability effects, such as gas blocking.

Although there may be differences between the log-derived and the test permeability, which is fact of life in real reservoirs, the log-derived permeabilities will find their way into the static and dynamic models. Practically, the permeabilities may be adjusted, either globally or near certain wells to make the predicted flow rates match the production data, in the simulator during the history-matching process.

Author: Markus Bernhart

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5. Value of information A petrophysicist should have an idea of the economic part of the work he is performing. He has to have a feeling, whether the cost of running a certain log is really justified, what means that it brings more money than it costs. In a typical oilfield model money is spent, until a discovery is made. In the following discovery there is a development phase, involving significant capital expense (called CapEx) on wells and facilities. When producing, money start to come back and the CapEx will be paid back. There will also be operating expenses (OpEx) and tax for revenues. At the payback time, the income will have covered the lowered CapEx and OpEx and the project starts to put off some profits. At any time the field has a future value (ignoring all the sunk costs), which is called the net present value (NPV). This NPV is calculated from production forecasts, together with assumptions about hydrocarbon prices, taxes, future OpEx and abandonment costs. It is important to know how information is related to NPV. The better and more information you have, the more wisely the CapEx may be spent, and the greater the revenues. But there will be an effect that diminishes the returns. This is shown in the following figure. Information will be reflected either in a raise of costs and NPV, although the NPV will fall exceeding a certain limit of information. In the case, that a constant value of money is spent, there comes a time during the life of a field, when the income is getting less, what can’t be stopped because there are no revenue-increasing decisions left. For example, getting a core out of a well one month before abandonment will be just a waste of money. At this point it is important to get a feeling for the amount of money, spent for logging. Let’s say there is a field of about 50-MMbbl and the facilities have to be designed. It can be helpful to use nuclear magnetic resonance (NMR) tools, which are assumed to always give correct answers, in all the early development wells, what costs about half a million dollars, if there is a chance, of let say 30%, that the stock tank oil initially in place (STOIIP) is seriously underestimated and could be 75-MMbbl. In the case that these logs are not run, and the 500,000$ are not spent, there is a 70% chance, that the facilities are designed correctly. Then the field may realize an NPV of lets say 500 million $. However, there is a 30% possibility, that the STOIIP is in fact 75-MMbbl. With the same utilities, an NPV of 650 million $ may be achieved, but by using fitting facilities for this case, an NPV of may be 700 million $ may be reached. The estimated additional monetary value (ΔEMV) of using the NMR log can be evaluated by: ΔEMV = (0.3 * 700 + 0.7 * 500 – 0.5) – (0.3 * 650 + 0.7 * 500) = 14.5 million dollar

19 The costs for information

Author: Markus Bernhart

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20 Decision tree

Remember, that running the NMR logs in this case is expected to make a profit, but this logging method doesn’t add the 25-MMbbl to the reservoir. Most of the 75-MMbbl will be produced anyway, but the NMR allows you to make the right decisions for an optimal output. Practically tools may lead to not completely the right results, but there is a confidence expressed by a fraction R. It can happen, that you expect field of lets say 75-MMbbl and in real it is only of a size of 50MMbbl. With the facilities of the bigger field you might make a NPV of only 400 million $. A help for decision making can be a decision tree, shown in the following picture. Calculating the EMV the same way as before: ΔEMV = (R * (0.3 * 700 + 0.7 * 500) + (1 – R) * (0.3 * 650 + 0.7 * 400) – 0.5) – ((0.3 * 650 + 0.7 * 500) with an R value of 0.5, results in an ΔEMV of: ΔEMV = 517 – 545 = -28 In this case, running an NMR log will cost the company 28 million dollars. With the above equation the value of R can be calculated, where using NMR tools, becomes worthwhile. By plotting R versus ΔEMV, you come to figure 18, where a good value of R can easily be read from. Such plots, maybe with additional techniques (e.g. further tool calibration, special studies…) to improve the reliability of the tool, are used to convince the management about the benefits of running various tools.

By the reason, that the loss in NPV when making facilities too small is much less than the costs of making them too large, the negative EMV of misleading information is generally higher than the positive EMV of correct information, in the early stage of a field. Small facilities may only lead to a later depletion, while greater facilities result in a loss of money. And do not forget, that you had to pay for the information too. If your field is older, the situation has changed. You might find out that the STOIIP of your field is higher than expected, but this will not lead to great changing in development, you will just make more money than expected. In the situation that you find out that the STOIIP is less, there’s nothing you can do against it, and while the acquisition cost remains the same, the value of information becomes less. Summarized, at the end of the life of a field, the costs of information play a more important role than the reliability of the data.

Author: Markus Bernhart

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21 ΔEMV versus R

The following points are investigated, when deciding whether a course of data acquisition was justified or not: 

The economic effect of finding additional hydrocarbons can not directly be correlated with the spot price of these hydrocarbons

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After getting some information, whether true or not, there’s also a possibility that you make wrong decisions.

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There is the chance that you don’t trust your data, or it just confirms with the assumptions you already made. Nevertheless you have to pay for any of this information.

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Some kind of data can be acquired only at a certain point of time. For example virgin data can be determined only at a very early stage of the field development. Therefore you should think about acquiring data for a later time.

Author: Markus Bernhart

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References Stefan M. Luthi (2001) Geological Well Logs. Their use in reservoir modelling: 3 – 7, 12 - 20 Toby Darling (2005) Well Logging and Formation Evaluation: 3 – 57, 119 - 124 Homepage of the company Baker & Hughes (www.bakerhughes.com) Homepage of the company Schlumberger (www.slb.com)

Author: Markus Bernhart

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