Ahmed, Khalid (Kuwait Oil Company) | Tyagi, Aditya (Kuwait Oil Company) | Saikia, Pabitra (Kuwait Oil Company) | Taqi, Fatma (Kuwait Oil Company) | Al-Rabah, Abdullah (Kuwait Oil Company) | Appel, Matthias (Shell) | Benham, Philip (Shell) | Zhang, Ian (Shell) | Mani, George (Core Lab) | Luague, Jefferson (Corpro)
Routine and Special Core analysis (RCAL and SCAL) are the cornerstone of Petrophysics Modeling and Formation Evaluation. In order to obtain the required information, it is important to have quality core, its processing and analysis. This paper summarizes current practices vis-à-vis improvements made in key technical areas.
Coring and core analysis are cost-intensive processes. Only quality data from representative core plugs can offset the high cost and can help to achieve the objectives of coring and core analysis. To obtain consistent quality core plugs, coring practice, on-site handling and plugging procedure have to be the best in class. Coring and core analysis in the shallow-depth Heavy Oil Fields in Northern Kuwait have been in place for some time. The processes like i) coring operation ii) on-site core handling and preservation iii) core slabbing iv) core plugging and finally v) core analysis are continually improved.
In order to be efficient and cost-effective, all the above processes were re-visited, quality gaps identified and improvements implemented by incorporating unconsolidated formation characterization from the available extensive petrographic studies. For example in the coring practice front, coring and core handling protocols were modified for sour heavy oil-bearing formations noticed in parts of the fields. On-site dry ice was used in addition to the prevalent practice of normal freezing. In the laboratory analysis front, obtaining representative plugs and getting useful results from them were the key challenges. Compared to the previous practice of liquid N2 injection from top only during core slabbing by band saw, liquid N2 injection from both top and bottom resulted in improved core integrity. The previous practice of plunge cutting of plugs with liquid N2 was continued. Before any analysis, Computer Tomography (CT) scan of the plugs was performed to discriminate plug-integrity related issues.
This paper discusses lessons learnt from past coring and core analysis processes and their impact on heavy oil development. Improvements to these processes as cost-effective measures are presented through real examples. Recommendations for improvement include field procedure, laboratory process, and usability of the tests performed, which may be useful to the industry where heavy oil core analysis is used.
Hertel, Stefan A. (Shell International Exploration and Production Inc.) | Rydzy, Marisa (Shell International Exploration and Production Inc.) | Anger, Benjamin (Shell International Exploration and Production Inc.) | Berg, Steffen (Shell Global Solutions International B.V.) | Appel, Matthias (Shell International Exploration and Production Inc.) | de Jong, Hilko (Shell International Exploration and Production Inc.)
Digital rock technologies were developed to augment traditional core analysis and led to a much improved understanding of the microstructure of many rock core types. However, to produce an upscaled description of the reservoir, one must consolidate the measurements in scale over six orders of magnitude. Here, we show that a whole-core CT scan may serve as the natural link between the length scales of digital rocks and modern logging tools. While the CT scan contains a fingerprint of the structure of the reservoir, the digital rock models show the microscopic composition of each CT-scan voxel. For upscaling purposes, we established a quadratic correlation between the gray values in a CT scan and the porosities measured on core plugs. This correlation allowed us to generate a synthetic porosity log of millimeter resolution. After that, the length scale was increased using moving averages in the vertical direction. We investigated a thin-bed reservoir with layers of halite-filled sandstone alternating with layers free of halite at variable layer thicknesses. In this reservoir, the resulting synthetic porosity log compared well with the NMR log porosity within the uncertainty band over a total depth interval of 53.6 meters. We propose that field decisions could be accelerated if the quadratic correlation parameters can be generalized for these types of sediment. In this case, one may generate synthetic porosity logs as soon as the CT scan is available, which is typically the first step in standard core analysis.
Rydzy, Marisa B. (Shell International Exploration and Production) | Anger, Ben (Shell International Exploration and Production) | Hertel, Stefan (Shell International Exploration and Production) | Dietderich, Jesse (Shell International Exploration and Production) | Patino, Jorge (Shell International Exploration and Production) | Appel, Matthias (Shell International Exploration and Production)
In this study, digital rock analysis was combined with a variety of experimental core-analysis measurements to investigate the effect of salt saturation and distribution on the porosity and permeability of halite-cemented core samples. Medical and micro-X-ray CT scans of core sections and 2.54-cm (1-in.) diameter plugs indicated that the halite generally occurred in the form of distinct layers. High-resolution micro-X-ray computed tomography (MXCT) images acquired of 0.6-cm diameter plugs revealed that, on the pore scale, halite appeared to be pore filling. Pores were either completely filled with halite or did not contain any halite at all. It was also observed that halite preferentially occurred in the larger pores associated with larger grain sizes. The porosity and permeability results, both measured experimentally on the core plugs and calculated by segmentation of the MXCT images, demonstrated the obstructive effect of halite on storage and flow as well as the decline of both properties with increasing salt saturation. Comparison of calculated and measured values showed that the measured porosity could be up to 6 porosity units (p.u.) higher than the calculated one, while the measured permeability of core plugs after salt removal was an order of magnitude lower than the one obtained by lattice Boltzmann simulation. One possible reason for this discrepancy may be the stratified nature of the samples. While the fully salt-saturated plugs appeared homogeneous in MXCT images, post-flood MRI images revealed that the plug was composed of layers with different MRI intensities, i.e., different amounts of water-filled porosity. Consequently, the petrophysical parameters calculated for the miniplugs may only be representative for a section of the core plug. The results of the MRI-assisted corefloods emphasized the importance of considering different scales when interpreting and applying the results of digital rocks analysis.
Al-Yaarubi, Azzan (Schlumberger) | Edwards, John (_) | Guntupalli, Suryanarayana (Petroleum Development Oman) | Al-Qasmi, Liali (Petroleum Development Oman) | Kechichian, Jackie (Petroleum Development Oman) | Al-Hinai, Ghalib (Petroleum Development Oman) | Bachman, Nate (Schlumberger) | Al-Amri, Aryaf (Schlumberger) | Appel, Matthias (Shell International E&P)
A method for measuring the spatial and temporal change in a reservoir resulting from injecting an enhanced oil recovery (EOR) agent is time-lapse saturation logging of an observation well positioned between the injectors and producers. The saturation logs reveal the conformance of the EOR flood vertically across the reservoir. Conventional observation wells are completed in cemented steel casing; however, this limits the choice of logging measurements that can be used. If fiberreinforced plastic (FRP) casing is used, then it is possible to log nuclear magnetic resonance (NMR), which is a fluid-volume-sensitive measurement that can be obtained only if the casing is nonconductive and nonmagnetic. This measurement is necessary if the EOR process makes it difficult to interpret the response of the conventional saturation logs. An EOR fluid that changes the aqueous phase salinity by an unknown amount will make the interpretation of resistivity and sigma logs uncertain, and one that changes the wettability will also introduce errors in the interpretation of a resistivity log. For certain medium-viscosity oils in porous formations NMR-monitored corefloods have shown that this measurement can resolve remaining oil saturations to a precision of 5 saturation units. An advantage of NMR for monitoring EOR is the possibility of using a common physics of measurement at multiple scales.
In this EOR project, laboratory corefloods, a single pilot well, and the observation well logging were all monitored with NMR. Laboratory experiments were conducted on a low-field bench-top NMR magnet with a fluid injection sequence that matched the EOR scheme. In-situ measurements of the oil and brine saturations during the coreflood were conducted by using diffusionediting protocols and by relaxation measurements alone and were in quantitative agreement with gravimetric assays of recovered oil. This was followed by a loginject- log single-well in-situ evaluation, in which the alkaline surfactant polymer (ASP) fluid was transported downhole in a sample chamber and injected into the formation through a pencil-sized hole. Borehole electrical images, dielectric and high-resolution NMR logs were recorded before and after fluid injection. The final stage of EOR screening was a multiwell pilot program that included FRP casing in the observation well designed for NMR logging. The NMR tool employs a fixed magnetic-field gradient and operates at multiple frequencies and thus multiple depths of investigation from the casing wall. The different frequencies create thin “shells” of sample volume. The deeper shells measure entirely within the formation, which is beyond the casing and cement. The NMR logs recorded in the observation well prior to injection of the ASP agreed with the NMR logs at the waterflood stage of the laboratory and single-well pilot results. The results also showed that computed saturation is repeatable to within 5-s.u. or less.
Rambow, Frederick H.K. (Shell International Exploration and Production) | Dria, Dennis E. (Myden Energy Consulting) | Childers, Brooks A. (Baker Hughes) | Appel, Matthias (Shell International Exploration and Production) | Freeman, Justin J. (Shell International Exploration and Production) | Shuck, Michelle (Shell International Exploration and Production) | Poland, Stephen H. (Prime Photonics) | Dominique, Tyrone (Baker Hughes)
During the last several years, significant progress has been made in the use of fiber-optic technology for well and reservoir surveillance. While most effort in this field appears to be concentrated on the development of fiber-optic-based meters for temperature, pressure, and flow, comparably few publications have been made to date about the use of fiber-optic technology for monitoring deformations of well tubulars and casings.
In this article, we report on recent advances in our development of a real-time fiber-optic-based casing imager. This device is designed for continuous, high-resolution monitoring of the shape of casings or well tubulars and, therefore, enables the determination of strain imposed on the well. Small-scale and full-casing-sized laboratory tests have demonstrated that the latest generation of this system is sufficiently sensitive to detect casing deformations of less than 10°/100 ft and covers compressive and tensile axial-strain ranges from less than 0.1 to 10%. We will discuss the background technology, measurement sensitivity and strain-response characterization, as well as the scaleup work that has been performed to date. Our article also includes an overview of field-test results and illustrates how real-time deformation monitoring could form a significant component of reservoir-surveillance strategies.
Appel, Matthias (Shell E&P Technology Co.) | Dria, Dennis Edward (Shell Intl. E&P Inc.) | Freeman, Justin (Shell Oil Co.) | Rambow, Frederick H.K. (Shell Intl. E&P Co.) | Shuck, Michelle (Shell Int'l. E&P Inc.) | Childers, Brooks Allen (Luna Energy) | Dominique, Tyrone (Baker Hughes Production Quest) | Poland, Stephen H. (Baker Hughes)
During the last years, significant progress has been made in the use of fiber-optic technology for well and reservoir surveillance purposes. While most effort in this field appears to be concentrated on the development of fiber-optic based temperature-, pressure- and flow meters, comparably few publications have been made to-date about the use of fiber-optic technology for monitoring deformations of well tubulars and casings.
In this article we report on recent advances in our development of a real-time fiber-optic based casing imager. This device is designed for continuous, high-resolution monitoring of the shape of casings or well tubulars and, therefore, enables the determination of strain imposed on the well. Small-scale and full-casing-size laboratory tests have demonstrated that the latest generation of this system is sufficiently sensitive to detect casing deformations of less than 10 degrees per hundred feet and covers compressive and tensile axial strain ranges from less than 0.1% to 10%. We will discuss the background technology, the measurement sensitivity and strain-response characterization, as well as the scale-up work that has been performed to-date. Our article also includes an overview of field test results and illustrates how real-time deformation monitoring could form a significant component of reservoir surveillance strategies.
This tutorial provides an overview of NMR fundamentals with the intent to familiarize the general reader with the physics of the NMR measurement. Background material is first presented, before petrophysical aspects of NMR are introduced. The focus of this tutorial is the determination of porosity from NMR, but pore-size determination and clay identification are also briefly discussed.
Standard formation evaluation of an exploration well in the U.K. southern North Sea was supported by magnetic resonance while drilling (MRWD).
In this paper we show that even in tight gas sands, MRWD provides information about porosity and producible fluid fraction and allows estimation of formation permeability.
This successful introduction of MRWD technology in a known hard-rock environment illustrates a powerful addition to the logging-while-drilling (LWD) tool suite.