This paper outlines a novel approach to an integrated 1D to 3D characterization and geomodeling of Vugular pore systems (VPS) in carbonate reservoirs. The study focused on capturing the various scales of the VPS and how they related to the 3D architecture. An integrated approach for detecting, characterizing and modeling the multi-scale VPS has been employed by utilizing multi-disciplinary datasets, that span from 3D seismic volumes, borehole images, production data to petrographic analyses. These datasets were analyzed and corroborated in the 1D, 2D and 3D domains to validate and define the occurrence and architecture of the VPS within the reservoir. Eventually, a 3D geo-cellular model of the VPS is constructed by honoring diagenetic proxies and experiments, VPS flags, fluid flow behavior and seismic attributes geobodies. VPS are observed at nearly all scales of datasets (i.e. geoscience and reservoir engineering data). They also occur at different scales of pore size ranging from millimeters to multi-meters. Many of them are even beyond the resolution of conventional whole core and basic well logs. A complete set of static and dynamic data allows a classification of the VPS into several classes based on their size, intensity and effect on reservoir properties and flow rates. Diagenetic proxies, well-based experimental variogram analyses and seismic-based geobody extraction further confirmed their architecture and distribution within 3D space. Their ramified patterns within the proximity of structural crestal areas tie quite consistently with well and seismic data. This architecture is further supported by possible hydro-dynamic corrosive fluid behavior that potentially had longer residence time in the crestal areas during late burial diagenesis stages. A modeling-while-interpreting workflow is also configured to model the VPS in 3D interactively and confirm the VPS occurrence on a well-by-well basis. This method is applied directly to the 3D full-field model and is linked to an interpretation platform. This unique approach contributes to the reduction of ambiguity in subsurface data and analysis.
Petroleum Development Oman (PDO) has some 30 active fields in the North of Oman which produce from both Carbonates and Clastics. About a third of all wells in the North are horizontal and/or multilateral of various vintages with a large variety of completion environments i.e. barefoot, perforated cased hole, Elastomer Zonal Isolation Packer (EZIP) completions and Electric Submersible Pump (ESP) wells. Historically, down-hole flow patterns encountered in these wells have been very difficult to measure and interpret. Therefore, it was intended to use the most comprehensive suit of logs to determine real time three phase flow entries along the well bore. Only when all three phases are quantified is it possible to have confidence in appropriate well work-overs, interventions and/or increase reservoir understanding. The logging aimed to improve production optimization and proper well and reservoir management. This paper intends to review the advance production logging jobs performed in a year period from 2006 to 2007, from several fields in the North of Oman. The paper includes the following:–Pre-job planning, recommended logging procedures, operational planning and considerations for different type of wells, well completion strategy, etc.–Factors influencing horizontal production logging jobs–Evaluation, log quality control and interpretation results–Optimization of success rate through candidate selection and best practices A summary of all the advance production logging job objectives and results will be shown. The main learnings per field and completion type along with way forward recommendations will also be summarized. Introduction PDO commenced drilling horizontal wells in the North of Oman back in the 80's. Since then, most development projects used a high proportion of horizontal and multilateral wells to access reserves. Historically, downhole inflow patterns encountered in these horizontal wells have always been challenging to measure and interpret. The usual challenges of horizontal production logging are described in another paper, "Production Logging Low Flow Rate Wells with High Water Cut1". Recently, the FlowScan Imager (FSI*) was identified as a viable production logging tool to increase our understanding of real time three phase flow with an aim to assist in production optimization and proper well and reservoir management. This paper will review and analyze a number of FSI* logging jobs conducted in the fields of North Oman. With any well related operation it is important to discuss the success rate of obtaining data. Figure 1 shows the FSI* jobs' success rate in producing oil Fields of North Oman. The traffic light colors indicates whether the job was successful (green) or not (red). "Technical success" (amber) is based on whether the logging objectives set prior to the job were met or not. In some cases, well work-over entries were performed based on the findings from the FSI* job and some production gains have been recorded. However, this paper does not intend to analyse the work over entry gains versus cost. The high success rate (13 successful FSI* logging jobs out of the 18) was partially due to proper candidate selection, but most of all due to proper planning (Success with 3 out of 6 in Field 1, 5 out of 6 in Field 2, 3 out of 3 in Field 3 and in Field 4, 2 out of 3). Of the remaining 5 unsuccessful jobs, 2 were due to tool failures which were not re-attempted and 3 where either failure to log the entire interval of interest or could not be logged due to operational constraints giving poor quality data.
Diagenetic nodular anhydrite observed in fluvio-aeolian-lacustrine and glacial sandstones has significant implications to reservoir quality. This type of nodular cement is spatially and volumetrically variable within these reservoirs. Its presence impacts subsurface formation evaluation and porosity calculations. Thus, the investigation of these nodules was carried out using: core image analysis; thin sections petrography; micro computed tomography (MicroCT) scans; bulk rock X-Ray Diffraction (XRD); sulfur & strontium isotope analyses. Where core was unavailable, geochemical data and resistivity-based image logs were used to expand the anhydrite characterization to derive field wide distributions. Bulk rock XRD and thin section-based petrographic studies indicate that the mineralogy of the study sandstones is dominated by quartz (>90%), with minor clay, and the presence of variable amounts of localized anhydrite as diagenetic nodular cements. The habitat of anhydrite nodules displays a substantial size variation, with nodules ranging from millimeters to several centimeters in scale. The larger nodules are easily identified visually in core samples and on borehole image logs. To investigate the origin of the anhydrite, sulfur and strontium isotope analysis were used to understand the relative timing of the nodule's development within the paragenetic sequence. Results from the sulfur and strontium isotopic analyses are consistent with the understanding that the anhydrite nodules are a late stage emplacement. A semi-quantitative "Anhydrite Abundance Index" (AAI) was calculated across key wells within the fields to establish the anhydrites regional distribution. The AAI uses the dry weight fraction of calcium and sulfur from geochemical logs to determine the volume of anhydrite. These volumes were further calibrated to volumes obtained through geochemical analysis of core samples, which is key to calculating the correct anhydrite volume required for formation evaluation. Regional distribution mapping created from this volume data suggests a widespread presence of the anhydrite nodular cementation. Understanding the relative abundance of anhydrite volumes is important when investigating the reservoir quality, especially if underestimating its presence may affect log-based porosity calculations and subsequently permeability calculations. The in-place quantification of the anhydrite nodular cement in 1D also enabled research to further the understanding of post-depositional, geochemical and geographic controls on the subsurface modelling and reservoir quality prediction.
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