The porosity response of four proposed generator-based neutron tool concepts is studied using Monte Carlo simulation of the radiation transport. The objective is to examine, at a fundamental level, the potential of these sources to replace americium-beryllium (Am-Be) sources primarily in openhole applications and, briefly, in a through-casing application of interest to a number of operators. The accelerator-based sources include a dense-plasma focus (DPF) alpha-particle accelerator and deuterium-tritium (DT), deuterium-deuterium (D-D), and deuterium-lithium (D-7Li) neutron generators. The DPF uses the (a-Be) reaction to generate a neutron spectrum that is nearly identical to that from an Am-Be source. D-T and D-D neutron generators use compact linear accelerators and produce, respectively, 14.1 and 2.45 MeV neutrons. The D-7Li neutron spectrum resembles the Am-Be spectrum at lower energies, and has a neutron peak at 13.3 MeV
Simple spherical-geometry models that do not include tool and borehole are used to explore the basic physics. An openhole tool-borehole-formation configuration is used to explore key observations from the simpler model. In both models, the responses at various detectors are examined to understand the behavior of the ratios constructed. Sensitivity to formation conditions, such as lithology, presence of gas, low porosity and presence of thermal absorbers, and operational conditions, such as tool standoff, are examined. A casedhole configuration is also analyzed where neutron counts are the only method for zonal correlation.
The state of neutron-generator technology is discussed in terms of neutron yield, target properties, power demands etc., which are important considerations for implementing such generators in nuclear logging tools.
Along-hole depth is the most fundamental measurement in our business of making and using subsurface measurements, tying together all downhole data services provided. Driller’s way-point depth (DwpD) correction is applied to calibrated drillstring length and, together with an associated uncertainty, provides true along-hole (TAH) depth. An earlier paper outlined DwpD theory. This paper reviews the methodology and describes the results of applying DwpD corrections in a field trial.
Logging-while-drilling (LWD) measurements are typically recorded using uncorrected driller’s depths while drilling down. When the drillstring is pulled out of hole (POOH) in a simple sliding state, DwpD correction of drillpipe depth can be applied in a way similar to the way-point correction used to correct wireline depth. The parameters necessary to calculate the correction include downhole temperature measured at the bottomhole assembly (BHA) and pipe axial tension measured as surface hookload (SHL). Both of these are measured as the drillstring is withdrawn from the well. These are the inputs to the DwpD thermal- and elastic-stretch corrections and these are applied to the calibrated length of the individual pipes that make up the drillstring.
DwpD corrections were applied in a field trial where two deep deviated off shore appraisal and development wells with along-hole depths of around 14,000 ft (Well 1) and 15,000 ft, (Well 2) that were drilled using composite 5- and 5.875-in. tapered drillstrings. Because the entire drillstring was under tension while being pulled out of hole, the corrections applied, amounting to around 100 ft at total depth (TD), are larger than those that might be expected using conventional methods. The field test results show that DwpD corrected depth is comparable to WLL logged depth.
The results show sensitivity of the corrected along-hole depth measurement to the tension profile, the temperature profile, the wellbore geometry and the drillstring architecture. The results highlight the differences between the originally logged LWD depth, the WLL logged depth and the DwpD corrected depth. The associated uncertainty of the DwpD corrected TAH depth then provides a context within which these differences can be resolved.
Openhole microfracturing stress tests often fail at great depth because a fracture cannot be initiated, even with application of the equipment’s maximum pressure. This paper presents methodological developments enabling feasibility assessment and design analysis of such tests with respect to fracture initiation. Emphasis is put on quantitative risk assessment and control to account for the large uncertainty that generally prevails, before a test, in the in-situ conditions controlling the initiation pressure. Given equipment’s pressure specifications, we calculate the probability of successfully initiating a fracture for a range of in-situ conditions and design options. Global sensitivity analyses are carried out to map the chance of success over this range. Finally, on test completion, we use test results to reduce the uncertainty space. We illustrate the method with a synthetic case example. Uncertainties prove easily factored in and run-time is less than one second for adequate sampling of the uncertainty space. The analysis informs on how successful or unsuccessful a planned test is likely to be and, when necessary, on the most effective ways to improve the chance of success, including in terms of tool configuration, well and test design, and rock formation targets. Uncertainty reduction based on completed tests results should improve the success rate from one test, or one test campaign, to the next.
My affair with well depth started almost a half-century ago. In the early 1970s, wireline logging tools were not combined (e.g., separate logs were run with neutron, density and resistivity tools). As a logging engineer I was, in the jargon used in these distant years, cranking, that is manually adjusting the depth, of subsequent runs so that curves peaks and troughs would correlate. It was a challenge in laminated formations, as it was easy to mistake one bed with the previous one or the next one. The interpreter, most often performing interpretation with a pencil and a slide rule on paper or fi lm records, would handle possible mismatches with art. When digitally recorded data entered in the mid-seventies, 6-in. sampled data were much more difficult to correlate exactly. Logging companies developed many programs to achieve perfect correlations between concertina-like curves. The fact that few people remember the names of these programs confirms that they were not successful. At that time, aligning logging curves was the primary concern. Logger’s total depth needed to be close to driller’s total depth, as should logger’s casing shoe depth and driller’s casing shoe depth, but this could be easily arranged.
This is a three-part tutorial of a workflow for evaluating unconventional resources including organic mudstones and tight siltstones. Part 1 reviews the unique challenges and we provide an overview of the proposed workflow. Part 2 describes in more detail the many components of the workflow and how they come together to determine the storage capacity of the reservoir. Finally, Part 3 links the petrophysical results to the production potential in terms of fractional flow and water cut.
One of the most important functions that the petrophysicist provides is the estimation of accurate storage properties. In the oil and gas industry, storage defines the opportunity, and flow pays the bills. Estimation of storage is more than just estimation of porosity and water saturation. It begins with accurate assessment of rock composition which begets accurate porosity and subsequently water saturation. However, storage estimation need not end there. With an understanding of fluid type and properties, and with the application of appropriate equations of state that describe the variation of formation volume factor, bubblepoint or dewpoint pressure, oil viscosity and density as a function of temperature, pressure, GOR, API gravity and gas gravity, very accurate assessments of oil in place (OIP), gas in place (GIP), and water in place (WIP) are possible in profile. These profiles are then integrated into cumulative storage volumes by bench.
Blount, Aidan (Shell Exploration and Production Company) | McMullen, Adam (Shell Exploration and Production Company) | Durand, Melanie (Shell Exploration and Production Company) | Driskill, Brian (Shell Exploration and Production Company)
Core analysis has historically been held as the ground truth for petrophysical model calibration. With the advent of unconventional resources, vendors and operators alike have scrambled to improve and develop core analytical techniques to accurately measure the quality of these tight reservoir rocks. Fluid saturations are a critical component of this evaluation, and much eff ort has been made to quantify the as-received gas, water, and oil components of the pore space using Dean-Stark extraction, retort, and other complementary analyses.
While much of the focus has been on assessing the core in the condition it arrives in the lab, a key question remains: how have the fluid saturations changed as the core sample has traveled from the reservoir to the testing facility? Prior observations in the Permian Basin indicate an average of over 35% as-received air-filled porosity, suggesting that a third or more of the in-situ pore saturating fluids are never directly measured in the lab. This creates a significant uncertainty around estimation of in-place volumes and calibration of a predictive water saturation model.
Getting this analysis right is critical to one of the core tenets of a practicing petrophysicist: performing highly predictive evaluations that enable profitable and sustainable business decisions.
An example from the Permian Basin, West Texas, USA, is presented comparing a variety of core-acquisition techniques. In this example, whole core, rotary sidewall cores, and pressurized rotary sidewall cores were each acquired over the same reservoir intervals. An experiment was designed to help mitigate fluid loss in the various methods, helping guide the petrophysicist on the reconstruction of accurate in-situ saturations. Additionally, this sampling program was designed to compare the methods in both their operational practicality and quality of core acquired.
A common assumption is that the void space at surface was previously occupied by hydrocarbons that escaped the rock due to gas expansion; this statement will be tested. Is there any water loss from in-situ to lab conditions? Can whole core or pressurized sidewall coring—with a controlled drawdown to atmospheric pressure—help maintain in-situ fluid saturations and retain oil within the rocks? Finally, does this understanding increase the predictive power of a practicing petrophysicist tasked with evaluating the productivity of unconventional reservoirs? These questions are addressed through detailed testing and analysis of the acquired rocks and other data.
In recent years, more horizontal well targets in unconventional reservoirs are being designed to stay within narrow stratigraphic-target windows. These narrow windows can be as thin as 10 feet and require active geosteering to keep the wellbores within the target. It is a difficult challenge to meet the target objectives when steering with a standard omnidirectional gamma-ray (GR) tool alone. The lack of azimuthal sensitivity in these tools makes it difficult to determine whether the wellbore is approaching the top or bottom of the target window while using real-time data during drilling, or using memory log data even after drilling the lateral section.
To solve this problem, the industry is beginning to turn to azimuthal GR tools. GR tools assist in determining the relative stratigraphic position of the drilling assembly. This is done as it cuts up-section or down-section, when approaching or crossing bed boundaries. In real-time, only up- and down-looking azimuthal GR curves are available from some service providers. However, others have real-time multisector data and may even provide real-time GR images. The quality and amount of the real-time data is impacted by telemetry limitations, drilling noise and vibrations, and the rate of penetration.
There is a wide range of commercial azimuthal GR tools available that vary in design and quality. Azimuthal GR tools can be contained within almost any section of the bottomhole assembly (BHA). This includes the drilling system (at- or near-bit), or a component of a sonde-based measurement-while-drilling (MWD) system, or built into the body of a logging-while-drilling (LWD) system. The different tool designs that dictate the placement of the GR detector within the tool cross section can lead to different azimuthal sensitivities and tool performance.
We compare the expected performance of three different azimuthal GR tools based upon Monte Carlo nuclear modeling to the actual performance using real data from three wells. The modeling results demonstrate different vertical resolution among the different tools and different quadrants of the same tool. The geometrical relationship between the well path and the formation layer is shown in measured depth and true-vertical-thickness (TVT) reference spaces. This is the basis for processing and interpreting GR and other borehole images. We also demonstrate a method to reverse-engineer the depth of image (DI) for each of the three tools. We use forward-modeling geosteering correlation techniques to closely match to the actual field data. Then the up- and down- GR sector data acquired in horizontal well sections are verticalized in TVT reference space, noting the total off set and deriving a DI. The theoretical analysis-based modeling results are shown to compare favorably to the field results.
Kausik, Ravinath (Schlumberger-Doll Research) | Freed, Denise (Schlumberger-Doll Research) | Fellah, Kamilla (Schlumberger-Doll Research) | Feng, Ling (Schlumberger-Doll Research) | Ling, Yanchun (Schlumberger-Doll Research) | Simpson, Gary (Independent Consultant)
Two-dimensional nuclear magnetic resonance (NMR) T1-T2 maps are fast becoming a routine methodology for fluid typing in unconventional shales due to their sensitivity to molecular mobility. The differences in the mobility of the different components of unconventional plays—ranging from solid kerogen to the fluid components of viscous bitumen, clay-associated water, oil in oil-wet organic pores to fluids (oil and water) in the mixed-wet inorganic pores and natural fractures—is measured by this methodology to determine the fluid types and their confining environments for the construction of universal 2D maps of different wells. One of the biggest challenges for the universal application of this methodology is the need for an understanding of the impact of the variation in frequency on the applications of different wireline, LWD, wellsite and laboratory tools which work at different Larmor frequencies, and of the variation in temperature between different basins, wells, or even multiple depths within a well. The main objective of this paper is to understand the changes in molecular mobility of the different fluids in shales as a function of temperature and their influence on 2D NMR T1-T2 maps measured at different frequencies.
For this purpose, we performed NMR relaxation experiments on the extracted bulk components of shales, such as kerogen, bitumen, and light oil, and also investigated them under confinement, such as bitumen and oil in organic kerogen pores, oil and water in inorganic pores, other than clay-associated water. The experiments were carried out as a function of frequency, ranging from 10 kHz to 20 MHz, and temperature, ranging from 30 to 90ºC. This enabled us to obtain a fundamental understanding of the 2D NMR T1-T2 maps for different fluids in both the bulk state and under oil-wet or water-wet confinement, with different pore sizes and surface relaxivity. The theoretical model we present shows how the frequency dependence and temperature dependence arise from the same description of the molecular motions of the fluids.
For E&P companies, well integrity during the production cycle is of paramount importance for safeguarding health, safety, and the environment (HSE) and for maintaining the license to operate. In this paper, we describe the development of a composite well cement with specific enhanced acoustic signatures that can be detected by traditional sonic logging tools as well as next-generation ultrasonic tools. This new acoustically responsive cement uses specially engineered particle fillers that act as acoustic band-gap filters and contrast agents at specific frequencies. The resultant acoustic signature can thus be analyzed to determine the mechanical integrity of the cement as well as the mechanical stress experienced by the cement.
During the development of this technology, finite-element analysis and simulations were used to determine the acoustic response and guide the design of the new cement. The composite cement was produced on the laboratory scale, and the acoustic band-gap features were confirmed using vibrational measurements. Ultrasonic sensors were then used to determine the acoustic response of subscale composite structures, including under mechanical load and in simulated environmental tests. Finally, shallow buried pipes with cemented annuli and engineered voids were constructed for pilot testing. During that final stage, a slimhole monopole sonic logging tool was used to map the cement location and determine the location and relative degree of mechanical loading.
Stress was applied using a variety of methods and mapped along the wellbore. The results indicated improved acoustic detection using sonic bond-log tools including uniquely identifiable cement placement, enhanced void discrimination, and localization of loaded regions. The acoustically responsive cement allows distinguishing between fluids and lightweight cement, monitoring of formation depletion and reservoir compaction, and increased knowledge of wellbore stresses in the oil field. Furthermore, the material has the potential to be continuously monitored with an acoustic interrogation system for remote, real-time indication of cement stress and integrity on a zone-by-zone basis.
Skalinski, Mark (retired Chevron ETC) | Mallan, Robert (Chevron ETC) | Edwards, Mason (Chevron ETC) | Sun, Boqin (Chevron ETC) | Toumelin, Emmanuel (Chevron ETC) | Kelly, Grant (Chevron ETC) | Wushur, Hazaretali (Chevron ETC) | Sullivan, Michael (Chevron Canada Resources)
Assessment of the “net pay” is an essential part of reservoir characterization and resource determination. Standard methods usually involve the use of porosity, permeability and water saturation cutoffs to define net reservoir, net pay and perforation zones. However, there are no industry standards for the definition of cutoffs and their application in the reservoir characterization workflows. Assessment of net-pay cutoff s in carbonates is more challenging than in clastics due to inherent heterogeneity of pore architecture and permeability. Historically, the success rate of flowing perforations is low, and operators tend to “overperforate” to capture all potential flowing zones.
This study was undertaken to redefine pay categories and provide methods of cutoff determination in carbonates, leveraging applications of NMR logging, capillary pressure, and in-situ flow measurements. The new category of “gross hydrocarbon” is introduced to describe the rock charged with hydrocarbon. The new methods defining “gross hydrocarbon” are described: NMR shape analysis and hydrocarbon-charged pore-throat (HCPT) or R10 method. NMR T2 shape and 2D shape analyses define the minimum porosity and/or permeability with detectable hydrocarbon signal. The T2 shape analyses were performed for several carbonate fields around the world, yielding a porosity cutoff for hydrocarbon charge varying between 1.5 and 3.5%, depending on reservoir type.
The HCPT or R10 method used an extensive MICP dataset from these carbonate fields to predict an entry pore-throat radius corresponding to potential hydrocarbon charge. The predicted entry pore-throat log combined with the pore-throat size corresponding to capillary pressure at specific height above free-water level (HAFWL) allowed to define zones which were not penetrated by hydrocarbon charge due insufficient capillary pressure. Definition of those zones corroborated results from the NMR shape analysis. Both methods are restricted to hydrocarbon column.
The next cutoff investigated was the minimum value of permeability associated with observed flow of in-situ fluids indicated by wireline pressure test or production logs. This cutoff would correspond to the conventional “net reservoir” definition. The use of permeability mitigates the need for porosity cutoff s, which usually vary by rock type. The study performed in the different carbonate reservoirs yielded permeability cutoff s varying between 0.01and 1 mD.
Practical examples from Tengiz, Karachaganak, PZ, West Africa and Permian basin validate the consistency between methods and the validity of statistical predictions of R10 pore throat. The methods presented here can be applied to any conventional reservoir.