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Collaborating Authors
density measurement
A Novel Interpretation Model for Cased Hole Density Measurement
Li, Yulian (University of Electronic Science and Technology of China) | Zhang, Qiong (University of Electronic Science and Technology of China) | Jin, Ya (China Oilfield Services Limited) | Niu, Decheng (China Oilfield Services Limited) | Meng, Yuexin (China Oilfield Services Limited) | Liu, Feng (China National Offshore Oil Corporation) | Hu, Yating (University of Electronic Science and Technology of China)
Abstract The application of thru-casing logging is essential to obtain formation parameters and control the operational risks under complex well conditions. However, thru-casing density measurement proves more challenging due to gamma's weak penetrating power as compared to neutrons, etc. More importantly, the quality of cement, which is difficult to evaluate quantitatively downhole, casts a significant impact on formation density measurement. To obtain accurate thru-casing density in scenarios where cement information is incomplete or uncertain, a new interpretation model is introduced in this work. The model is implemented based on the recently introduced four-detector gamma density tool, and mainly includes three aspects: 1) A detector model and formation model whose solution targets at both formation density and cement density. 2) Cement invasion model consisting of mud, water and methane. It serves as a constraint to define mathematical limits to reduce the effects of cement uncertainty. 3) According to the prior information, the cement invasion model corresponding to each depth is automatically determined to constrain the formation model. The application of the proposed model in an oilfield is presented to attest its reliability. The thru-casing density obtained from the model matches well with open-hole density, and cement output is regarded reasonable judging from previous work on cement evaluation, which proves the applicability of the model in real oilfield logging. Introduction The development of logging technology provides important formation parameters such as porosity, permeability, and oil and gas saturation for reservoir evaluation, which is of great significance to the exploitation of oil and gas reservoir resources. Under complex well conditions (deep wells and complex well trajectory), the conventional logging curves (natural gamma and resistivity) cannot meet the needs of reservoir evaluation. Gamma-gamma density measurement is basic but important for reservoir evaluation, especially for gas reservoir identification. In conventional open-hole wells, the risk of radioactive logging may not be effectively controlled, while cased-hole measurement can avoid some possible engineering risks and reduce the operation period. At the same time, re-evaluation of recorded wells also needs to be performed in cased-hole wells to improve management of hydrocarbon resources. Therefore, in cased hole, the study of gamma density measurement is necessary (Moake, 1998; Olowoyeye et al., 2020).
- Europe > Norway (0.46)
- Asia > China (0.29)
- North America > United States (0.28)
- Asia > Middle East (0.28)
Density Changes at Supercritical and Near-Critical Conditions by Increasing CO2 Content in Synthetic Hydrocarbon Mixtures โ A Comparison Between Experiments and Simulation Predictions
Aslanidis, Panagiotis (University of Stavanger) | Marinakis, Dimitris (Technical University of Crete/Institute of Petroleum Research) | Puntervold, Tina (University of Stavanger) | Gaganis, Vasilis (National Technical University of Athens/Institute of Petroleum Research) | Varotsis, Nikolaos (Technical University of Crete)
Abstract Carbon dioxide (CO2) injection is a well-known EOR-method to reduce residual oil in the pore network of oil reservoirs. It is also increasingly used as a means of mitigating the greenhouse gas emissions problem by storing it in geological formations. A key parameter to such attempts is the density of the rich CO2 mixture, which is formed downhole in the injection well, since it affects the swelling potential, oil formation volume factor, viscosity, hydrostatic gradient, fluid distribution and formation pore pressure. The density of the crude oil-CO2 mixture depends on the pressure-temperature conditions, the CO2 concentration and the dominant hydrogen compounds in the crude oil, i.e. whether they are aliphatics, aromatics, or naphtenics (cyclic structures). The PVT properties of the different CO2-hydrocarbon mixtures vary greatly and the available experimental data for tuning PVT simulators are scarce, especially for ternary mixtures at high pressures and CO2 concentrations. This study investigates the effect of CO2 concentration on the density of ternary mixtures containing CO2, methane, and a pure liquid hydrocarbon, which is either an alkane, aromatic or cycloalkane compound. The liquid hydrocarbons used in the study were normal heptane (n-C7), toluene (Tol) and cyclohexane (c-C6). The measurements were conducted at variable compositions, at temperatures of 50, 70, and 90 ยฐC, and at pressures ranging between 100 and 517 bar. The ternary mixtures were: Methane, toluene and CO2 at 1:1 molar ratio and CO2 concentrations of 14%, 27% and 72%, Methane, cyclohexane and CO2 at 1:1 molar ratio and CO2 concentrations of 19%, 47% and 68%. Methane, n-heptane and CO2 at constant molar hydrocarbon ratio (C1/n-C7) of 2:1 and varying CO2 concentrations of 23% and 75%, Some of the rich CO2 mixtures exhibited retrograde condensation behaviour at high temperatures. The results were compared against predictions from an EoS model (Peng Robinson Equation of State), coupled with volume shift parameters. The comparison between the simulation calculations and the experimental data indicated good agreement in the densities, but significant deviations in the boiling point pressures (Pb). As a result, the EoS model can be safely used to predict the CO2 mass storage potential of reservoirs of known pore volume such as the depleted ones.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Miniature Viscosity Sensors for EOR Polymer Fluids
Gonzalez, Miguel (Aramco Services Company: Aramco Research CenterโHouston) | Ayirala, Subhash (Exploration and Petroleum Engineering Advanced Research Centre, EXPEC ARC, Saudi Aramco) | Maskeen, Lyla (Exploration and Petroleum Engineering Advanced Research Centre, EXPEC ARC, Saudi Aramco) | Sofi, Abdulkarim (Exploration and Petroleum Engineering Advanced Research Centre, EXPEC ARC, Saudi Aramco)
Abstract There are currently no technologies available to measure polymer solution viscosities at realistic downhole conditions in a well during enhanced oil recovery (EOR). In this paper, custom-made probes using quartz tuning fork (QTF) resonators are demonstrated for measurements of viscosity of polymer fluids. The electromechanical response of the resonators was calibrated in simple Newtonian fluids and in non-Newtonian polymer fluids at different concentrations. The responses were then used to measure field-collected samples of polymer injection fluids. The measured viscosity values by tuning forks were lower than those measured by the conventional rheometer at 6.8 s, indicating the effect of viscoelasticity of the fluid. However, the predicted rheometer viscosity versus QTF measured viscosity showed a perfect exponential correlation, allowing for calibration between the two viscometers. The QTF sensors were shown to successfully produce accurate viscosity measurements of polymer fluids within the required polymer concentration ranges used in the field, and predicted field sample viscosities with less than 5% error from the rheometer data. These devices can be easily integrated into portable systems for lab or wellsite deployment as well as logging tools for downhole deployment.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
Abstract Drilling fluids are subjected to large variations of pressure and temperature while they are circulated in a well. This span of pressures and temperatures is so large that the mass density of the drilling mud differs from one depth to another. For a precise estimation of the hydrostatic and hydrodynamic pressures, it is therefore important to have a good estimation of the pressure and temperature dependence of the mass density of drilling fluids. Usually, the mass density of drilling fluids is manually measured with a mud balance. The pressure and temperature dependence of the mass density of the fluid, i.e. its PVT behavior, is then estimated based on the PVT behavior of its components and their relative proportions. However, variations in the composition of the fluid mix and uncertainties on the PVT behavior of each components, may lead to inaccuracies. To circumvent these limitations, an apparatus that measures directly and automatically the PVT behavior of the drilling fluid contained in a pit has been designed. The setup measures both the mass density and the speed of sound in the fluid at specific conditions of pressure and temperature. From the speed of sound in the liquid mix, it is possible to estimate the adiabatic compressibility. The device also utilizes a heat exchanger from which the thermal conductivity and specific heat capacity of the drilling fluid can be estimated. Combining the specific heat capacity, thermal conductivity and the adiabatic compressibility, the isothermal compressibility can be calculated. By combining measurements made at different conditions of pressure and temperature, a PVT model of the drilling fluid is estimated. By providing automatically, and on a continuous basis, the actual PVT behavior of drilling fluids, drilling automation systems can gain in precision and at the same time, their configuration can be simplified, therefore making them more accessible to any drilling operation.
Abstract Uncertainties in the drilling process result in safety factors or safety margins sufficient to minimize risks in the drilling process. These safety margins represent inefficiencies in the system. This paper will discuss a method for reducing uncertainty as it relates to well bore pressures and hole cleaning to eliminate or reduce these inefficiencies, quantify the rates of penetration that can be achieved, and illustrate the expected wellbore pressures generated by these rates of penetration. When data is collected manually, the nuances of fluid changes are lost between property measurements. This paper will illustrate the difference between calculating equivalent circulating densities (ECD) with manually collected mud report data and fluid properties collected in real time and the impact that this can have on optimizing the rate at which the operator can drill and trip pipe. A patent-based methodology will be presented, in which real-time drilling and fluids data are captured and utilized to model ECD pressure data related to the bore hole. The actual and modeled data are statistically analysed to infer information about how rapid a rate of penetration (ROP) may safely be employed to optimize drilling results. Data will be presented demonstrating the impact that small improvements in fluid parameters and drilling operations can have over the course of drilling a well. The role that a real-time hydraulics software model plays in providing predictive analytics for ROP optimization will also be discussed. Predictive analytics enable operators to look several stands ahead of the bit to determine if the ROP drilled will cause issues in the future. This enables the identification of the maximum ROP that can be drilled versus optimizing instantaneous ROP. This enables operators to optimize casing-to-casing time.
- Information Technology > Data Science > Data Mining (1.00)
- Information Technology > Architecture > Real Time Systems (1.00)
To investigate phase behavior of heavy oil with hydrocarbon solvent at a typical in-situ condition of about The phase behavior of the heavy oil (12 wt.%) mixed with 22 C and 5 MPa, the combined measurement system was hydrocarbon solvent (88 wt.%) has been investigated used to measure ultrasonic P-wave velocity and density at experimentally via in-situ P-wave velocity and density the in-situ condition, to observe the phase behavior and measurement, density measurement of gas-exhausted oil, bubble point pressure at the room temperature with and phase behavior observation. Suspended asphaltenes are decreasing pressure, and to observe asphaltenes' behavior hardly identified by velocity and density measurement, but simultaneously.
- Research Report > New Finding (0.51)
- Research Report > Experimental Study (0.51)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Managed Pressure Drilling (MPD) allows one to drill through formations with narrow pressure windows, thereby making those formations that cannot be drilled with conventional techniques accessible. It also provides the capability for early detection and safer handling of well control events. This technique requires accurate estimation of the annular pressure profile and the delta mass flow rate. These measurements can be improved through accurate density and mass flow rate measurement at the high pressure (7500 psi) input side of the well. Since no good metering technologies exist to make these measurements, the objective was to develop a high pressure density and mass flow rate sensor. A comprehensive review of all existing flow rate and density measurement instruments suggested that an X-ray based sensor was the best option for the high pressure fluid line. Multiple experiments were conducted to determine the electrical power range (voltage and power) for the X-ray tube that would work best for mud between densities in the range of 8 to 20 ppg. Experiments were then conducted to test the accuracy and feasibility of techniques developed for density and volumetric flow rate measurement. Based on these experiments, an X-ray source and detector were identified and a sensor was designed for inline use on 4 inch pipes. Two approaches were developed to estimate density using the sensor. The first was an empirical approach where sensor gray level values were directly mapped onto mud density values though in laboratory experiments. These mappings can then be used in the field to estimate density. The second was a model-based approach that estimates density based on the Beer Lambert's law. Both these approaches were tested experimentally using drilling muds of different densities and compositions. A mechanism that uses X-rays to determine volumetric flow rate was also designed and tested using both simulations and experiments. A real-time calibration subsystem had to be added to the sensor to preserve measurement accuracy and precision over time. Based on encouraging results from simulations and experiments, a laboratory prototype was built and is currently undergoing flow loop tests. This is the first time an X-ray mass flow rate measurement sensor has been designed to be used on high pressure lines. Preliminary findings indicate that no existing sensors used for similar applications can match the measurement accuracy and frequency that may be offered by this technology. Development of this sensor would improve the safe drilling of complex wells with narrow drilling windows.
Effect of Hydrothermal Alteration on Material Properties in a Carlin-Style Gold Deposit and Developing a Method to Delineate Material Domains for Numerical Model Geometry-Building
Perry, A. P. (Mine Design Engineering) | McKinnon, S. D. (Queen's University) | Kalenchuk, K. S. (Mine Design Engineering)
ABSTRACT: Spatially broad surface deformation was detected over the Leeville underground mining complex, which includes dewatered stoping operations of Carlin-style hydrothermal gold deposits in northeast Nevada. Geologic, groundwater, and extraction data were reviewed to form hypotheses of the causes and controls of the deformation, which were poorly understood. It was hypothesized that the hydrothermally altered materials hosting the orebodies form controls on ground behavior because they affect the mechanical properties of the rock mass. To investigate this hypothesis, 3-D material domains of altered and unaltered materials were needed. Because no dataset on alteration intensity was available covering the entire project area, multiple datasets were utilized, including data mining of the drill dataset to produce consistent alteration intensity rankings, density measurements, density interpreted from gravity surveys, and geologic interpretations. These datasets were used to delineate regions of the rock mass with styles of alteration that result in weaker and less stiff materials, and these 3-D geometries were subsequently used to designate material domains in a numerical model. This case study demonstrates a methodology for amalgamating multiple datasets to increase data coverage and improve confidence in the spatial modeling of geomechanical domains. The methods developed here would likely have application at nearby sites and in areas with similar geologic conditions for numerical model geometry-building. 1. INTRODUCTION Surface deformation can be produced by both underground mining or groundwater extraction, and subsurface geology can form controls on its expression in multiple ways. The mechanical properties of intact rock are generally a function of lithology and subsequent alteration processes, and consequently these factors can influence ground behavior when a rock mass is subjected to mining or groundwater pumping. A broad, irregular shaped deformation pattern was identified by InSAR methods in the region overlying the Leeville underground mining complex, which includes extraction of multiple Carlin-style sediment-hosted gold deposits using longhole stoping with backfill and cut and fill mining methods. Cumulative InSAR displacements measured between 2004-2010 are shown in Fig. 1.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Native Element Mineral > Gold (0.91)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (0.67)
- Data Science & Engineering Analytics > Information Management and Systems > Data mining (0.57)
- Well Drilling > Wellbore Design > Wellbore integrity (0.56)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (0.49)
Abstract In the current market, operational geology and geoscience asset teams have clear and aggressive financial reduction targets that need to be met without compromising the formation evaluation (FE) requirements of a well construction project. Advances in drilling and completion technologies and practices for deep-water wells commonly require operators to drill larger borehole sizes throughout the well construction process. For deep-water subsalt wellbores, this often implies exiting a thick salt layer with borehole deviation in borehole sizes ranging from 14.5 to 17.5 in. This paper introduces a unique 9.5-in. nominal collar size logging-while-drilling (LWD) density tool that makes it possible to address the FE challenges encountered in large borehole sizes. Any LWD method that can provide crucial cost-effective and accurate FE data can add value to well drilling and logging programs. The new tool provides density and photoelectric measurements in large-diameter boreholes. It also contains an ultrasonic sensor that can provide accurate borehole geometry information, which is useful for identifying stress-related breakout and providing accurate estimates of borehole volume for later placement of cement for zonal isolation. In such settings, formation density measurements are crucial for determining key evaluation parameters, such as porosity and rock mechanical properties, but acquisition of these measurements can be challenging using existing LWD technologies. In addition, real-time structural dip information for subsalt environments provides insight for the interpretation of the geological structure of the field but is often difficult to obtain in large-diameter boreholes. Several case studies demonstrate the value added by the new tool and its breadth of application, as well as the implications for pre-job analysis, bottom-hole assembly (BHA) modeling, data-acquisition procedures, sensor response analysis, and economic benefits to the operator. The capability of acquiring logging data for interpretation purposes and to fulfill specific regulatory requirements without negatively affecting the drilling program provides a desirable cost-management opportunity. The results presented here provide a reference for appropriate business cases to help justify the use of this unique LWD technology in drilling and logging projects involving large-diameter boreholes.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (0.35)
- Geology > Geological Subdiscipline > Geomechanics (0.34)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.47)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract Ability to identify casing collars in real-time is critically important for whipstock casing exit operations, because milling through casing collars could cause significant loss in rig time, excessive damage and even failure of downhole equipment, and potential blockage of the exit window by casing collar spinning. Running wireline to identify casing collars is the typical solution to address the challenge, but incurs additional rig time and cost. This paper present a new technology to locate casing collars in real time with Gamma Ray density measurement, deployed on drill pipe, eliminating the need for a dedicated wireline run. Multiple case histories of field testing the technology in North Sea, covering a wide range of casing sizes from 7-in and 18 5/8-in, are presented as well. The Gamma Ray density measurement is used for identifying casing collars by detecting the differences in density readings between collar and casing. Gamma rays are continuously emitted from a nuclear source as the density tool moves in the wellbore, and the readings of the near and far detectors, after signal travels through and interacts with casing and formation, are interpreted to calculate density. Density readings are transmitted to surface in real-time through mud-pulse telemetry and are processed to visualize casing collar locations in a log. The new technology was successfully field tested in North Sea in multiple wells covering a wide range of casing sizes, from 7-in up to 18 5/8-in, with different depths and inclinations. The operational processes and results from the field tests are discussed in this paper. The casing collars were successfully located in each field test, proving the robustness of the technology over a broad range of application parameters. It was discovered from the field tests that the bottomhole assembly (BHA) configuration, tool orientation, tool string rotational speed, sensor standoff and logging speed are critical to clearly identifying casing collars. This paper presents a new method of using the drill pipe deployed Gamma Ray density measurement to detect casing collars in real-time to optimize whipstock placement for improved reliability and efficiency of casing exit operations. It also provides the best practices of applying the technology in a wide range of well and casing configurations.
- Europe > United Kingdom > North Sea (0.46)
- Europe > Norway > North Sea (0.46)
- Europe > North Sea (0.46)
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