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Recent developments in pulsed neutron instrumentation open up new opportunities for petrophysical surveillance. Understanding the relation between a nuclear attribute and a recovery mechanism is a key element in selecting the appropriate running mode for a specific instrument. Developing a nuclear modelling capability allows us to screen various nuclear attributes for a given environment taking into account, specific rock, fluid and completion conditions to investigate the sensitivity of attributes to different recovery scenarios. There are a limited number of experimental tests pits limiting our ability to replicate the complexity of nuclear attribute responses to the variety of fluid displacements and well completions. Imperfections with cement and gravel pack further complicate the nuclear attribute response and should be taken into account during the nuclear model process. Benchmarking the nuclear models against controlled environments (man-made defects) provide some confidence in utilising nuclear forward modelling to design the logging program ahead of the job. This allows us to optimise rig time and maximise the data acquisition during well work opportunities. This method can be used in feasibility studies and petrophysical interpretation utilizing nuclear tools in different areas of petrophysical surveillance. Nuclear modelling can help to engineer gravel pack (specify the amount of Gadolinium enrichment), define the nuclear attributes that can be further used for gravel pack evaluation, and can also help in selecting the right tool from suppliers for monitoring multicomponent fluid saturations. In this paper we present some case studies to illustrate the application of nuclear modelling in the selection of attributes and tools for completion and reservoir surveillance. The results from experimental tests provide us with confidence in the quality of results from nuclear modelling. A robust model requires detailed information from core, fluids and completion. While all multidetector pulsed neutron instruments utilize the same physical principles and record similar basic measurements, there are differences due to tool geometry, electronics and interpretation algorithms. Screening nuclear attributes and selecting the appropriate tool for the job has a significant impact on rig time and acquiring quality data. Improving the quality of the acquired data will have a direct impact on the quality of the calculated results which will in turn lead to more effective well work and reservoir management.

Accurate determination of the propped fracture geometry compared to the stimulation design can help fine-tune geomechanical models and to optimize future hydraulic fracture treatments. Conventional methods to evaluate fracture height with logs use radioactive tracers pumped downhole together with the proppant. Subsequently, natural gamma ray spectroscopy logs are run to detect the tracers; however, safety and environmental concerns, together with regulations regarding transportation, storage and use of radioactive materials, can limit the use of these tracers. Newly developed proppant techniques allow detection without the need of using radioactive elements. Special compounds coat the substrate or are mixed with the proppant material. These interact with neutron logs, making it possible to evaluate the propped fracture height, and in certain cases, have a qualitative idea of the fracture width. Two approaches used by major proppant manufacturers consist of: (a) compounds that are activated by a neutron source, and (b) compounds that absorb neutrons (high capture cross section) and can be detected using conventional compensated neutron logs (CNL) or pulsed neutron capture (PNC) tools. Both PNC and CNL have a shallow depth of investigation, only a few inches away from the borehole, and therefore they indicate the propped fracture height in the near-wellbore region providing a first estimate where the proppant is placed. This paper will present the results of the neutron absorbing approach under challenging conditions in dual casing strings in wells located in the northern area of Saudi Arabia. The methodology applied uses a comparison of pre-fracture log count rates and post-fracture count rates, with reduced post-fracture count rates observed in zones containing proppant, using both CNLs and PNC tools. The experience has provided information about the sensitivity of each logging device and allowed the comparison to other methodologies (temperature logs) and the formulation of recommendations.

Traditional fracture-height and/or proppant-placement evaluation following a hydraulic fracture stimulation treatment has relied on the detection of radioactive (R/A) tracers pumped downhole with the proppant. While this technique has proven useful, it raises environmental, safety, and regulatory concerns and issues. In some areas of the world, transport and use of R/A tracers is prohibited. The proppant placement determination method described in this paper eliminates the downhole placement of R/A materials. A high thermal neutron capture compound (HTNCC) is incorporated into a ceramic proppant during manufacturing in sufficiently low concentration that it does not affect proppant strength or conductivity. Proppant is then detected using standard compensated or pulsed neutron tools, with detection based on the high thermal neutron capture of the compound relative to the surrounding downhole constituents. Two detection methods use a comparison of before-frac log-count rates and after-frac count rates, with reduced after-frac count rates observed in zones containing proppant. Another detection method, especially useful when formation gas saturations change, involves only the after-frac log. This paper will describe the methodology and results of an application of the new detectable proppant in the T sand of the Villeta and Caballos formations of Juanambú field in the Putumayo basin of Colombia. The results obtained from this novel technology provided the operator an improved understanding of the geomechanical characteristics of the formations and the achieved fracture dimensions. Additionally, this information will help improve future stimulation treatments. This paper should be beneficial to all completion engineers looking for methods to determine fracture height and/or proppant placement in an environmentally acceptable manner.

Abstract A new technique is discussed and tested in this work for proppant placement determination. A high thermal neutron capture compound (HTNCC) is inseparably incorporated into a ceramic proppant during manufacturing in sufficiently low concentration that it does not affect proppant properties. Proppant is detected using standard compensated neutron tools or pulsed neutron tools, with detection based on the high thermal neutron absorptive properties of the compound relative to downhole constituents. Compared to the traditional radioactive tracer (RA) techniques, the new detectable proppant is not radioactive so there are no HSE or regulatory issues. Additionally, since the high thermal neutron absorbing compound is placed in the proppant during the process of manufacturing, there is no requirement for special handling or mixing processes at the well site. Specifically, proppant is detected using after-frac compensated neutron logs combined with corresponding before-frac logs. Increased thermal neutron absorption by the compound reduces count rates in the near and far detectors, with approximately the same percentage reduction observed in each detector, leaving the near-to-far detector count ratio (N/F) unchanged. One detection method utilizes a comparison of before-frac log count rates and after-frac count rates, with reduced after-frac count rates observed in zones containing proppant. A second detection method, especially useful when formation gas saturations change, involves only the after-frac log. Since the near to far detector count ratio is unaffected by proppant, after-frac count rates predicted from the ratio will also be unaffected. These computed/synthetic count rates will be greater than the observed after-frac count rates in intervals containing proppant. Nuclear Monte Carlo modeling was performed to demonstrate the validation of this technique employing both compensated neutron logging tool (CNT) and pulsed neutron capture (PNC) logging tools. Two field examples from China are illustrated in this paper. The final interpreted locations of proppant are shown in the field examples. Introduction Hydraulic fracturing has been frequently used to increase hydrocarbon production especially in formations with low porosity and/or low permeability. Hydraulic fracturing operations can be conducted in horizontal, deviated, and vertical boreholes, and in open-hole wells or cased wells through perforations. The description below focuses on frac applications in cased boreholes in generally vertical wells, however analogous concepts are generally applicable to most frac situations. In hydraulic fracturing, the high-pressured, sometimes viscous, frac fluids exit the borehole via perforations through casing and cement, and cause the formation to fracture. At the same time, the high-pressured frac fluid carries proppant, such as sand, resin coated sand or ceramic proppant and places them in the fracture. Generally, the induced fracture extends laterally a considerable distance out from the wellbore into the surrounding formations, and extends vertically until the fracture reaches a formation that is not easily fractured above/below the desired frac interval. The direction of the least principal stress within the formation determines the azimuthal orientation of the induced fractures. In the case of viscous gelled frac fluids, gel "breakers" are added in the fluid slurry to reduce the viscosity of frac fluid after a desired time delay. This can enable fracturing fluid to be removed from the fractures and formation during production and leave the proppant in place to keep the induced fractures from closing.

The assessment of reservoir productivity and subsurface hydrocarbon can be significantly enhanced through an understanding of formation mineralogy and organic carbon. Such information allows petrophysicists to resolve ambiguities in their predictions of reservoir hydrocarbon potential. While core samples are a prime source for exact formation mineralogy, excellent results can also be derived in a timely and cost-efficient manner from in-situ log chemistry measurements of the rock. A direct measurement of the formation's elemental concentrations is achieved using a gamma ray scintillation sensor in combination with a 14-MeV pulsed-neutron generator. The most important element measured is carbon, as it may provide a direct indication of reservoir hydrocarbons. This paper presents a method for determining the amount of organic carbon in subsurface formations using a pulsed-neutron mineralogy tool and a natural gamma ray spectroscopy tool. The natural, inelastic, and capture gamma ray energy spectra from these instruments are used to extract the chemistry of the subsurface formation being investigated. The elemental concentrations measured include Al, C, Ca, Fe, Gd, K, Mg, S, Si, Th, Ti, and U. Carbon is very difficult to measure without the inelastic spectrum generated from a pulsed-neutron source. An interpretation process, based upon the geochemistry of petroleum-bearing formations, is employed to derive the lithology and mineralogy which leads to the interpretation of the carbon measurement. The oil saturation can be computed in conventional reservoirs, assuming that the amount of carbon in excess of that required for the inorganic matrix mineralogy is part of the pore fluid as hydrocarbon. The direct carbon measurement is also important in laminated shaly sands or in low-salinity reservoirs, where oil saturation determination from indirect measurements, such as resistivity, is not compatible with the environment. In other formations the carbon can be determined to be a component of the rock matrix as kerogen or coal, both of which are uniquely identified with this logging system. Kerogen becomes extremely important in the evaluation of shale gas formations. Field examples are presented to illustrate the effectiveness of the carbon measurement.

A new openhole logging service, RockViewSM, has been developed which provides lithological and quantitative mineralogical information for accurate formation evaluation. The assessment begins with elemental formation weights and follows with an interpretation of lithology and mineralogy. Lithologies are divided into general categories including sand, shale, coal, carbonates, and evaporites. Potentially identifiable minerals are quartz, potassium-feldspar, albite, calcite, dolomite, siderite, anhydrite, illite/smectite, kaolinite, glauconite, chlorite, pyrite, and others. The logging system utilizes an electronic pulsed source to send high energy neutrons into the surrounding formation1-8. These neutrons quickly lose energy as a result of scattering, after which they are absorbed by the various atoms within the ambient environment. The scattered as well as the absorbed neutrons cause the atoms of the various elements to emit gamma rays with characteristic energies. These are measured with a scintillation detector, resulting in both inelastic and capture gamma ray energy spectra. A matrix inversion spectral fit algorithm is used to analyze these spectra in order to separate the total response into its individual elemental components. The prominent measured elements associated with subsurface rock formations include calcium, silicon, magnesium, carbon, sulfur, aluminum, and iron. Potassium, thorium, and uranium are measured separately with a natural gamma ray spectroscopy instrument9-11. The tool response is characterized for each individual element by placing it into formations of known chemical composition. Interpretation of the data begins with an assessment of the elemental formation weights, which then leads to a determination of lithology and mineralogy. Each step in the process is guided by the examination of ternary plots containing selected elements. Magnesium is an extremely important part of the interpretation process since it distinguishes dolomite from calcite and helps to identify various types of clay. Data from field examples is presented in order to illustrate the effectiveness of this technology.