Technology Focus: Formation Evaluation (February 2024)

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 93557, "The Fracture Characterization and Fracture Modeling of a Tight-Carbonate Reservoir: the Najmah/Sargelu of West Kuwait," by O. Fonta, Beicip-Franlab; H. Al-Ajmi, N.K. Verma, and S. Matar, Kuwait Oil Co.; V. Divry, Beicip-Franlab; and H. Al-Qallaf, Kuwait Oil Co., prepared for the 2005 SPE Middle East Oil and Gas Show and Conference, Bahrain, 12-15 March. The Najmah/Sargelu reservoir of west Kuwait is a tight-carbonate oil reservoir in which porosity and permeability result from the fracture network. A multidisciplinary integrated approach combined geology [borehole-imaging (BHI) logs, cores, and wireline logs), geophysics [seismic facies analysis (SFA)], and reservoir-engineering data [production, production-logging-test (PLT), and well-test] to identify the main types of fractures, to predict their occurrence in the reservoir, and to determine the hydraulic properties of the different fracture types. Introduction The objective of a detailed geological and hydraulic characterization of the fracture network within the Upper Jurassic Najmah/Sargelu reservoir was to identify the main geological drivers of natural-fracture occurrence, measure fracture hydraulic properties, and, eventually, use discrete fracture modeling to compute the equivalent fracture properties (porosity, permeability, and block sizes) required for reservoir simulation. This objective was achieved through integration of geological, geophysical, petrophysical, and dynamic data by use of workflows and methods implemented in fracture analysis and modeling software. The main tasks during the project were the following. - Fracture analysis from cores. - Fracture analysis from BHI logs. - Integration of the 3D-seismic data set. - 3D fracture modeling. - Hydraulic characterization of the fracture network. - Computation of the fracture properties in the reservoir grids. Background The study area was approximately 2000 km2 and covered four fields. The reservoir structures are gentle, elongated anticlines. The top-of-reservoir depth ranges from 3350 to 3650 m. The Najmah/Sargelu reservoir has a generally high degree of lateral continuity and gradual thickness changes. The formation has alternating layers defined by volume of shale, Vsh, from well logs of clean limestone (Vsh <30%), shaly limestone (30%< Vsh <60%), and calcareous shale (Vsh >60%). Fifty wells were logged in the reservoir. Cores were available from 21 vertical wells, and BHI acoustic images were available on 18 wells; 10 wells had both cores and BHI logs available for the study. Matrix quality is generally very poor, dominated by micro-porosity (<8%) with low permeabilities (<0.01 md). Locally, higher matrix porosities and permeabilities may be found in Units 5 and 6 of the Sargelu limestones. Production is mostly from the fracture net-work in reservoir Units 2, 3B, 5, and 6.

Summary The main objective of this study was to extract fracture data from multiple sources and present it in a form suitable for reservoir simulation in a fractured carbonate field in Oman. Production is by water injection. A combination of borehole image (BHI) logs and openhole logs from horizontal wells revealed that water encroachment occurs mostly through fracture corridors and appears as sharp saturation spikes across fracture clusters. Dispersed background joints have little flow potential because of cementation, lack of connectivity, or small size. Image logs indicate that fracture corridors are oriented dominantly in the west/northwest direction. Most of the several injector/producer short cuts are also oriented in the west/northwest direction, supporting the view that fracture corridors are responsible for the short cuts. Flowmeter logs from vertical injector or producer wells intersecting a fracture corridor show a step profile. A comparison of the injection or production history of wells with or without a step profile provided a means to calculate permeability enhancement by fracture corridors. The field has more than 300 vertical wells and nearly 20 horizontal wells, which allowed us to generate detailed fracture-permeability enhancement and fracture-corridor density maps based on injector and producer data, short cuts, mud losses, openhole logs, and BHI logs. We also were able to build stochastic 3D fracture-corridor models using corridor density from dynamic data and orientation from BHI logs and seismic data. Fracture-corridor length and width were tied to fracture-permeability enhancement using wells with both image logs and production data. The fracture-permeability enhancement maps were verified independently by waterflood-front maps. Notwithstanding the uncertainties, the fracture data were sufficiently accurate and detailed to generate both single- and dual-porosity simulation results with good field-scale history match.

Until recently, reservoir characterization methods in the industry were limited to use of seismic technologies in exploration of oil and gas and had a very constrained role in production and development. In the past, using characterization for development fields was considered a very perilous task. Technological advancements and the risk-averse mindset have significantly expanded the application of reservoir characterization. Today, reservoir characterization is the basis of any development plans made for a commercial field. Development of 3D reservoir modeling techniques to generate field development plans (FDPs) marked a step-change in reservoir characterization methods. Introduction of geostatistics and numerical simulation made it possible to build precise models to generate realistic field development scenarios. This is the state-of-the-art seismic-to-simulation method of reservoir characterization used in FDPs today. However, the struggle to estimate reservoir properties spatially away from the well continues. Surface seismic data provide excellent areal coverage but do not provide the vertical resolution required for a fine-scale reservoir model. Geostatistical methods reduce the uncertainty in spatial distribution of petrophysical properties from pseudo-point supports (wells) but are not calibrated spatially between the wells. Correspondingly, the fluid saturation distribution and the parameters used in dynamically calculating the same during numerical simulation are not calibrated in the interwell space. This paper details necessary data acquisitions and methods of calibration of 3D reservoir model to reduce uncertainty in the interwell space. The data acquisition methods have been available for some time, but have rarely been electronically incorporated in the 3D reservoir model and have been largely used to analytically guide the modeling and its inferences. A logical way of interpreting the results of acquisitions and calibrating the 3D reservoir model cell-by-cell is detailed in this paper.

Proposal Borehole images provide high-resolution information on the layering, texture, and dip of rocks and sediments and permit core-like description of subsurface reservoirs. Conventional openhole wireline logs. e.g., gamma, SP, resistivity, and porosity measured by nuclear, sonic, and NMR sensors provide complementary bulk petrophysical properties of formations. Thus, a proper integration of the electrical images with the conventional logs could provide an extremely powerful tool for reservoir characterization. However, image logs still remain a mystery for many E&P Operators. They are underutilized - largely because the workflows to integrate them with the conventional logs and other well or field data are not yet commonplace. This paper proposes standard computer-aided work-flows for the geological and petrophysical evaluation of the siliciclastic and carbonate reservoirs. The workflows involve integrating high resolution images with conventional open hole logs. Specially built software assists the user to identify lithofacies, depositional facies, and high frequency stratigraphic changes on the high resolution images. Sedimentary cycles and bed-sets and packages are then interpreted and combined with the other logs to generate electro-facies. Reservoir fluid volumes and estimation of netto- gross pay are included in the standard answer product. Results of the integration are then combined with the other well and field data to perform sequence stratigraphic analysis. The paper includes case histories of successful applications from the Permian and the Fort Worth Basins and from other basins in the US and Mexico. We demonstrate that the proposed integrated workflows can significantly enhance accuracy in reserves estimation and reservoir fluid flow modeling. These workflows can be applied to multi-well reservoir characterization by tying the key stratal surfaces and sedimentary features from image logs to seismic. Using image logs ultimately reduces uncertainties of the interpretation of external geometry, internal architecture, and lateral variations in oil and gas reservoirs. Introduction Although, a greater number of petrophysicists and geologists now routinely use borehole image logs** in their reservoir characterization programs, they do not appear to follow a set workflow to achieve a standard interpretation of the reservoir characteristics from borehole images. In part, lack of a consistent workflow is due to the fact that many users of image logs continue to view them only as pretty pictures of the formations exposed on the borehole walls. Partly, it is also due to the difficulties associated with up-scaling the very high resolution image logs when integrating them with other open hole logs. Finally, a part of the reason for lack of effective workflows may be lack of awareness and training with respect to the various image interpretation techniques that can reveal specific reservoir characteristics. Objectives of this paper are:to identify a standard set of reservoir characterization goals in E&P and review the role of image interpretation in achieving these goalsto recommend an interpretation workflow based on image processing software techniques to integrate borehole images and all the other open hole logs. It is hoped that this standardization would help maximize the value of borehole image logs and benefit petrophysicists and geoscientists in their global E&P efforts. ** Note - The terms image logs and imaging as used in this paper refer to the wireline electrical or acoustic borehole images acquired in either water- or oil based mud wells.

Optimizing hydrocarbon recovery in complex reservoirs requires a robust and precise reservoir characterization. This sometimes can be hindered by limitations in traditional single-measurement tools especially in reservoirs with complex architecture, which could impose challenges for optimal well placement due to variations in reservoir structure, formation dip, and rock quality. This paper discusses a novel three-dimensional (3D) holistic integration of electrical borehole imaging, far-field dipole sonic, and deep resistivity imaging in a directional wellbore drilled in a tight heterogenous carbonate formation. Borehole images enable the identification of reservoir rock properties and characterization of structural features that intersect the wellbore. Contrasts in electromagnetic resistivity measurements provide insights on fluid saturation and rock quality, whereas far-field sonic imaging offers details pertaining to distal reservoir layering and fracture extension. Using the strengths of each tool, this integrated approach provides comprehensive reservoir insights at and away from the wellbore. An automated 3D dipole sonic imaging workflow has been developed to detect and characterize arrival events in the filtered pre-migrated wavefield using a combination of tau-P event picking, ray tracing inversion, and 3D Slowness Time Coherence (STC) processing. The workflow results include 3D mapping of the reflectors along the well trajectory and their attributes such as true dip and azimuth. Quantitative comparison with borehole image logs helps assess lateral continuity of reservoir boundaries and identifies potential extension of fractures. A case study in a tight heterogenous carbonate reservoir is included herein to illustrate the novel approach effectiveness and business value. The results indicate that the wellbore crossed two different layers with distinct structural characteristics. The first layer is dominated by discontinuous conductive fractures with NE-SW strike orientation, whereas the second layer is more vuggy with fewer fractures. The deep shear imaging indicates that fractures have higher density in the first layer and extend up to 80 ft. away from the wellbore. These findings highlight the integrated approach benefits including reduced uncertainty and improved decision-making capabilities for optimized production operations.

Characterization of flow and transport in a fracture network at the EGS Collab field experiment through stochastic modeling of tracer recovery

A fundamental problem facing the petroleum industry is to effectively use the large amounts and diverse types of data that are collected to define and exploit stratigraphic and structural compartments that contain undrained hydrocarbons. The key is to build data-driven, deterministic geological interpretations to intelligently target infill wells. This approach is fundamentally different from that used in geostatistically-driven approaches which interpolate the sparse data support points without maximizing the value of the data that has been collected or geological knowledge. We describe a workstation tool and interpretation method for that allows one to combine, in 3D, well-based interpretation and quantitative analog information from fields or outcrops to make testable predictions about the location of geological bodies that are prospective infill drilling locations. This tool combines (1) 3D visualization in a common viewing environment of diverse data that are viewed at true scale (e.g., 3D surface seismic; vertical seismic profiles, reservoir simulation results, conventional wireline and borehole imaging logs, core photographs); (2) a well-based interpretation environment; and (3) an archive of digital 3D geological analog shapes and textures that one can use to relate textures seen in image logs or core images to those observed in analog data, i.e., other fields or outcrops. These shape and texture analogs can then be used to place geological bodies that can be rescaled and oriented in 3D. Comparison with seismic data may then support or refute these interpretations. We have applied this tool to the interpretation of the Atokan Bend Conglomerate in the Boonsville Field in north Texas, a mixed siliciclastic-carbonate succession containing deltaic, estuarine, and fluvial valley-fill sandstone reservoirs. The key to exploitation of this field is identifying sandstone bodies within the lowstand, incised valleys, which are commonly less than 500 meters in width, and 20 meters in thickness. By combining core, image log, and seismic information in the 3D visualization tool, we have recognized Bend Conglomerate reservoir sandstone bodies and further, we have been able to define them in inter-well space using sandbody shape analogs from the tool's digital archive. The key advantages of this approach are that we preserve information about the interpretation process and multiple hypotheses; we see all data at the appropriate scale; and we view the implications of the deterministic geological interpretations within the same data volume as our measured data. This provides a means of capturing and applying geological knowledge of analog formations, as well as tracking the steps in the interpretation process.

Distributed acoustic sensing in subsurface applications – Review and potential integration with artificial intelligence for an intelligent CO2 storage monitoring system

In this research, we used a combination of available data (core analysis and borehole image logs) to characterize the Judea Formation sediment fractures. The Judea Formation low-energy marine shelf sediments are made up of limestone in the upper half and dolostone in the lower. Some induced and enhanced fractures with an N-S striking direction were identified using FMI image logs. Furthermore, the rock naturally fractures with an NNE striking orientation. The characterization of fractures using core studies revealed that the limestone zone had a greater quantity of induced fractures than the dolomite zone. Within the dolomite zone, naturally occurring fractures are frequent; they are open or partially filled with secondary mineralization. Due to the breaking of the limestone matrix under compression during burial diagenesis, sealed fractures with calcite are primarily recognized in the limestone zone. Due to the plastic deformation/pressure solution of the soft carbonate host rocks, sealed fractures with clay are most prevalent in the limestone zone. Because of their link with the dolomitization that floated over the lower part of the Judea Formation section during diagenesis, sealed fractures with dolomite were primarily identified in the dolomite zone. As a result of the significant dolomitization, sealed fractures containing bitumen formed within the dolomite zone conduits, serving as hydrocarbon migration pathways. The paragenetic sequence is given, although it is stressed that many parts are still hypothetical owing to the inadequate database. Geological and/or other projects in the Euphrates Graben area can use help from such an integrated study.

Developing a giant sour gas field in the Upper Jurassic formation poses significant challenges due to strong heterogeneity, complex lithology, intricate structures, uncertain fluid composition/contacts, and ultra-high H₂S content. This paper aims to showcase how leveraging fit-for-purpose advanced technologies can enhance reservoir understanding and maximize production efficiency by strategically placing wells in thin layers with lateral facies variations. This process involves advanced wireline logging for reservoir characterization in the pilot hole, followed by objective-oriented Logging While Drilling (LWD) for horizontal well placement. A comprehensive wireline suite, including triple combo, acoustic, dielectric, neutron spectroscopy, NMR, and borehole image logs, were acquired to thoroughly assess reservoir properties. Wireline formation testing and sampling tools were deployed to accurately determine fluid types within each subunit, with strict precautionary measures in place due to ultra-high H₂S concentrations. Subsequently, the LWD Bottom Hole Assembly (BHA) was selected based on geological objectives and reservoir properties. Real-time well placement was collaboratively monitored by geologists, petrophysicists, and geosteering engineers to ensure optimal reservoir coverage in thin, laterally variable layers. This approach was successfully implemented across multiple wells. In the pilot holes, the integration of mud logs and advanced logging tools significantly enhanced reservoir understanding. Neutron spectroscopy logs identified a mixed lithology of limestone, dolomite, and anhydrite, effectively reducing uncertainties in porosity calculations. Dielectric log inversion enabled more accurate saturation estimates, particularly in zones where formation water resistivity and Archie parameters varied between layers. NMR logs provided permeability estimates in the heterogeneous formation, supporting optimized fluid sampling strategies and a more accurate reservoir model. Borehole image logs revealed both natural fractures and formation dips, contributing to a refined structural interpretation. Formation testing clarified fluid contacts and phase behaviors, reducing uncertainty in reservoir modelling. Horizontal well targets were defined based on the comprehensive insights gained from the pilot holes. During drilling, real-time LWD data—interpreted collaboratively by geologists, petrophysicists, and geosteering engineers—enabled precise navigation through thin, laterally variable reservoir layers over horizontal sections exceeding 10,000 ft. This integrated approach ensured optimal reservoir exposure, minimized drilling in non-productive zones, and mitigated operational risks in ultra-high H₂S environments. This case study demonstrates the successful application of a customized logging strategy in one of the world's most challenging sour gas reservoirs. The integration of advanced wireline and LWD technologies not only improved reservoir characterization and well placement but also set a benchmark for safe and efficient development in ultra-high H₂S, heterogeneous carbonate environments contributing valuable insights to future sour gas field developments globally.

Natural fractures occur over several orders of size magnitude. Accurately predicting the three-dimensional and multi-scale distribution of fractures in subsurface reservoirs is very difficult. Direct observations are limited to large-scale faults visible on seismic data and high-resolution, mostly small-scale, measurements of fractures intersecting the well, valid only in the direct vicinity of the wellbore. Analogue outcrop studies can be used to help fill in the gaps. The multi-scale properties of the natural fracture network exposed in the Cambro-Ordovician siliciclastic sequence in Petra, Jordan, are captured and it is investigated how these properties can be applied for the characterization of subsurface fractured reservoirs. The thesis consists of a series of chapters describing the geology of the study area, the results of the multi-scale fracture study in Jordan, followed by an analysis of the network connectivity using percolation theory and discrete fracture network models. The thesis is concluded by the results of numerical experiments where the influence of stress rotation on the re-activation of pre-existing fractures is investigated to help understand the evolution of complex networks consisting of multiple fracture sets.

The oil and gas industry has historically spent significant amount of capital to acquire large volumes of analog and digital data often left unused due to lack of digital awareness. It has instead relied on individual expertise and numerical modelling for reservoir development, characterization, and simulation, which is extremely time consuming and expensive and inevitably invites significant human bias and error into the equation. One of the major questions that has significant impact in unconventional reservoir development (e.g., completion design, production, and well spacing optimization), CO2 sequestration in geological formations (e.g., well and reservoir integrity), and engineered geothermal systems (e.g., maximizing the fluid flow and capacity of the wells) is to be able to quantify and map the subsurface natural fracture systems. This needs to be done both locally, i.e., near the wellbore and generally in the scale of the wellpad, or region. In this study, the conventional near wellbore natural fracture mapping techniques is first discussed and integrated with more advanced technologies such as application of fiber optics, specifically Distributed Acoustic Sensing (DAS) and Distributed Strain Sensing (DSS), to upscale the fracture mapping in the region. Next, a physics-based automated machine learning (AutoML) workflow is developed that incorporates the advanced data acquisition system that collects high-resolution drilling acceleration data to infer the near well bore natural fracture intensities. The new AutoML workflow aims to minimize human bias and accelerate the near wellbore natural fracture mapping in real time. The new AutoML workflow shows great promise by reducing the fracture mapping time and cost by 10-fold and producing more accurate, robust, reproducible, and measurable results. Finally, to completely remove human intervention and consequently accelerate the process of fracture mapping while drilling, the application of computer vision and deep learning techniques in new workflows to automate the process of identifying natural fractures and other lithological features using borehole image logs were integrated. Different structures and workflows have been tested and two specific workflows are designed for this purpose. In the first workflow, the fracture footprints on actual acoustic image logs (i.e., full, or partial sigmoidal signatures with a range of amplitude and vertical and horizontal displacement) is detected and classified in different categories with varying success. The second workflow implements the actual amplitude values recorded by the borehole image log and the binary representation of the produced images to detect and quantify the major fractures and beddings. The first workflow is

An integrated high-resolution image log, sequence stratigraphy and palynofacies analysis to reconstruct the Albian – Cenomanian basin depositional setting and cyclicity: Insights from the southern Tethys

Fractures, whether natural or hydraulic, serve as crucial pathways for fluid flow within rock formations. Because natural and hydraulic fractures are generated hundreds of meters underground, their parameters always seem to be a black box. Their influence on pressure propagation and well productivity, however, cannot be overstated. So how well are we doing in fracture evaluation and modeling? Fracture evaluation can be regarded as an inverse problem, wherein the structural characteristics of a system are deduced based on input and output signals. Our objective is to ascertain the distribution, orientation, connectivity, and properties of fractures through the mathematical and physical methods applied to field data. Generally, we can use fracture-evaluation techniques such as surface tilt fracture mapping, downhole tilt fracture mapping, microseismic fracture mapping, tracer testing, temperature logs, production logs, borehole image logs, downhole video, caliper logs, production analysis, and well testing. In parallel to fracture evaluation, fracture modeling assumes a computational approach to simulate fractures within subsurface reservoirs. We have various methodologies such as analytical, semianalytical, or numerical approaches to develop fracture models, including dual-porosity models, discrete fracture models, embedded discrete fracture models, and flow-net models. By means of fracture simulations, we can glean valuable insights pertaining to transient pressure behaviors, optimal production schemes, and estimation of ultimate recovery. Despite the significant progress made, a gap still exists between theoretical advancements and practical field application in fracture evaluation and modeling, because underground fractures are often more complex than initially expected and nonunique solutions for fracture evaluation are commonplace. Thus, fracture evaluation and modeling represent complex and interdisciplinary fields, requiring expertise in geology, reservoir engineering, geomechanics, simulation, and related disciplines. We also need continuous research endeavors and advancements in fracture evaluation and modeling techniques to augment our understanding of fracture behavior and reservoir performance in the oil and gas industry, as demonstrated in the selected papers and recommended additional reading. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212296 A Simple Analytical Model for Oil Production From Partially Fractured Reservoirs To Estimate Size of Finite Fracture Networks by Sait I. Ozkaya, Consultant SPE 209624 A Flow-Net-Based Method for History Matching and Production Prediction of Shale or Tight Reservoirs With Fracturing Treatment by Hui Zhao, Yangtze University, et al. SPE 209293 A Hybrid Embedded Discrete Fracture Model and Dual-Porosity, Dual-Permeability Work Flow for Hierarchical Treatment of Fractures in Practical Field Studies by Mun-Hong Hui, Chevron, et al.

Outcrop work represents the main source of analogs used to model subsurface reservoirs. Without such explanation of reservoir geometry, architecture, and characterization, producing subsurface formations would be largely uncertain. The aim of this paper is to build a geological static model for the Enjefa Beach outcrop exposed in Kuwait and use it to better understand subsurface reservoir architectures. This was achieved by acquiring several traverses along the outcrop, describing the various rock units, and understanding the depositional facies and facies associations. The next stage was to model each depositional unit as a separate zone embedded in an integrated model. This was followed by developing a forward synthetic three-dimensional seismic model to better understand how such reservoir architecture may appear in the subsurface. The final step was to use these findings in modeling a subsurface Cretaceous reservoir in northeastern Kuwait. The resultant model demonstrated that detailed geological complexities can be captured by conventional modeling techniques; in the model, the middle shoreface, upper shoreface, foreshore, and tidal channel complexes were statically modeled. Subsurface seismic data showed a series of highly sinuous meandering channels. Stacking patterns were found to vary among vertical, climbing, and compensational stacking patterns.