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The coal-seam gas (CSG) industry has long been considered as a high volume, low cost market. As the industry has matured, the selective application of high-tier technologies has realized a step change in performance and real-time formation evaluation results. We investigated whether a high-tier LWD multi-function service could provide a suite of quantitative real-time measurements in several deviated wells. The key objective was to reduce the amount of non-productive rig time spent waiting for memory data in order to confirm the completion design. Significant savings in rig time could be realised if reliable, high-quality real-time data enabled the early identification of coal seams and permeable aquifers such that the swellable packer and slotted liner completion design could be completed without the need for final memory logs.
The area of interest is characterized by thin Jurassic coal seams rather than thick Permian seams. It was critical to accurately identify thin coal beds in real-time whilst maintaining a high rate of penetration (ROP). Low-resolution data would result in poor completion design, underestimation of net coal reserves, and sub-optimal static models. Measuring coal thickness and properties can be difficult due to the fundamental differences between the formation evaluation measurements and their relative axial resolutions. The presence of thin coals can further complicate the interpretation. Another challenge was to optimize the real-time data transmission to prevent any limitation on the key directional drilling data parameters.
Conventional LWD logs (gamma ray, nuclear, and resistivity measurements) provide formation evaluation information while drilling. The selection of a rotary steerable system (RSS) was critical as it ensured directional control and avoided any sliding intervals over key aquifers and coal zones, thereby ensuring optimal LWD acquisition. Advanced formation evaluation options of the LWD data also included using dual-pass resistivity inversions for Rt/Rxo to determine the invasion profile in a permeable aquifer zone above the main coal-producing reservoir. Having this information in real-time was critical in guiding well-specific competition decisions. Induction and laterolog-type resistivity tools were run on one well to quantify differences in the measurements and to determine the best resistivity acquisition tool for CSG wells drilled with saline muds in freshwater formations.
The results showed that high-tier LWD technologies provide multiple benefits in CSG wells. The project was executed with all directional and logging objectives achieved. Quantitative real-time data was critical for completion decisions including ECP placement together with swellable packer and slotted liner designs. This resulted in significant cost savings which are important to major CSG developments operating within a low-cost operating model. LWD memory data provided a rich suite of additional measurements to complement the real-time data. Memory data was used for advanced reservoir analysis with industry-unique measurements.
Distributed acoustic sensing (DAS) inter-stage vertical seismic profiling (VSP) data were acquired during the stimulation of two horizontal shale wells in the Denver-Julesburg (DJ) Basin’s Hereford field. These data were analyzed to obtain induced fracture heights and fracture densities for use in fracture modeling and Stimulated Rock Volume (SRV) calculations. Inverted inter-stage VSP (also referred to as rapid time-lapse DAS VSP) data, transformed to an anisotropic seismic velocity model via rock physics relationships, were used to estimate stage-by-stage fracture height and density. Comparison of fracture height from multiple sources confirm the validity of fracture height calculations for the Niobrara fiber well, and the deeper Codell fiber well. When combined with other independent diagnostics such as microseismic, tilt (microdeformation), seismic rock properties, pressure, and distributed acoustic/temperature sensing (DAS/DTS) data, these estimates are validated for use in developing an optimized completion plan, as well as for use in calculating stage-by-stage stimulated rock volumes.
The Hereford field is located in the northern DJ Basin, Colorado, just south of the Wyoming state line. Similar to the giant Wattenburg field to the south, Hereford produces from the unconventional reservoirs of the Upper Cretaceous Niobrara Formation and the Codell Member of the Carlile Shale (Figure 1). Early in the life of the Hereford field, it was understood that the "complexity of the fracture system" would require significant analysis in order to understand and realize the reserve potential of the field (Anderson et. al., 2015). Early wells in the field, drilled between 2010 and 2012, were completed with relatively small completions and primarily accessed oil in the natural fracture systems. The very tight 0.5 to 3.0 mD permeability in the Niobrara B Chalk requires larger completion rates and volumes to access the matrix oil.
The Hereford Field contains pervasively naturally fractured zones as well as more matrix dominated areas. A production optimization project was initiated by HighPoint Resources in 2019 to understand the best practices for maximizing production from both the pervasively natural fractured parts of the field, as well as the more matrix dominated portions of the field, while performing completions in 23 wells on four pads within the field. This project was designed to shorten the cycle-time needed to optimize completions. Rather than execute well-by-well parameter variations that can take years to evaluate, this project was designed to test numerous completion scenarios with a variety of diagnostic tools in a short period of time. Evaluation of these completion parameter changes give the best chance of success. In addition to distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) on fiber optic cables cemented behind casing, numerous other techniques were utilized to evaluate these wells including surface microseismic, tilt (microdeformation), pressure gauges, micro-imaging, and a pilot well with a quad combo and dipole sonic. Additionally, the 2009-vintage seismic data were reprocessed and merged with adjacent surveys in 2019 including a new pre-stack inversion. (Raw data courtesy of Seitel).
Abstract With the increasing demand for hydrocarbons, unconventional reservoirs are gaining prominence and account for a large percentage of oil and gas production. However, these unconventional reservoirs inevitably include challenges that must be carefully managed while planning an extraction strategy to yield maximum recovery. This paper demonstrates the advantages of an integrated and automated well placement workflow to improve geosteering in complex unconventional reservoirs with maximum hydrocarbon recovery. Automated well placement technique is controlled by three primary components: (1) an integrated asset model; (2) availability of uninterrupted, real-time log data; and (3) appropriately selected well planning methods. Initially, a dynamically updatable model of subsurface geology is created that combines surface topography, and an initial well trajectory is planned. As the well progresses, new log data are added to the asset model, and an interpretation is made in real time. Incorporating real-time data helps to dynamically update the model and enable a comparison of planned vs. actual deviation surveys for course corrections. This procedure guides the geosteerer to update well plans, run feasibility analyses, and predict subsurface uncertainties ahead of drilling, thus, increasing the reservoir penetration and overall well productivity. Automated well placement while drilling is a relatively new concept and requires collaboration across various disciplines. Currently, such techniques are gaining importance among operators of unconventional resources as it enhances accuracy in well positioning and provides better production while reducing costs, drilling risks, and uncertainties. In addition, when targeting very thin, geologically complex reservoir layers, it provides a holistic view of the dynamically changing asset. The use of this approach will enable oil and gas operators to make collaborative, cross-domain decisions and streamline existing unconventional workflows.
Newby, Warren (Total SA) | Abbassi, Soumaya (Total SA) | Fialips, Claire (Total SA) | D.M. Gauthier, Bertrand (Total SA) | Padin, Anton (Total SA) | Pourpak, Hamid (Total SA) | Taubert, Samuel (Total SA)
Abstract The Upper Jurassic (Oxfordian to Late Kimmeridgian) Diyab Formation has served as the source rock for several world-class oil and gas fields in the Middle East. More recently it has become an emerging unconventional exploration target in United Arab Emirates (UAE), Saudi Arabia, Bahrain and its age-equivalent Najhma shale member in Kuwait. The Diyab is unique in comparison to other shale plays due to its significant carbonate mineralogy, low porosities, and high pore pressures. Average measured porosities in the Diyab are generally low and the highest porosity intervals are found to be directly linked to organic porosity created by thermal maturation. Despite low overall porosities, the high carbonate and very low clay content defines an extremely brittle target, conducive to hydraulic fracture stimulation. This coupled with a high-pressure gradient facilitates a new unconventional gas exploration target in the Middle East. However, these favorable reservoir conditions come along with some challenges, including complex geomechanical properties, a challenging stress regime and the uncertainty of whether the presence of natural fractures could enhance or hinder production after hydraulic fracture treatment. Only recently has the Diyab been studied in detail in the context of an unconventional reservoir. This paper presents an integrated approach allowing a multidisciplinary characterisation of this emerging unconventional carbonate reservoir in order to gain a better understanding on the plays’ productivity controls that will aid in designing and completing future wells, but already encouraging results have been observed to date.
Kosanke, Tobi (Independent Consultant) | Loucks, Robert G. (The University of Texas at Austin) | Larson, Toti (The University of Texas at Austin) | Greene, James (TerraCore) | Linton, Paul (TerraCore)
Abstract Hyperspectral imaging (HI) is a method of observing and enhancing geological rock properties that are not readily apparent visually. Originally developed for the mining industry, HI uses a combination of short-wave infrared light (SWIR) and long-wave infrared light (LWIR) to create a visual ‘map’ of the minerals on the surface of a core that respond to reflectance principles. HI, which requires no special preparation other than that the core be slabbed, clean, and dry, can be rapidly obtained and provides mineralogical and chemical results related to various energy emitted in wavelength spectrum by either halogen bulb reflectance (short-wave quantification) or heat reflectance spectra (long-wavelength quantification). We collected hyperspectral core imaging data of the Marathon 1 Austin Chalk Robert Todd core in central Louisiana to obtain detailed, high-resolution mineralogical and textural information and investigate the application of hyperspectral imaging as an integrative tool. Digital HI-derived single mineral curves calibrated to X-ray diffraction (XRD) were imported as curves to display mineralogical variations with depth alongside overlays showing the textural relationships of the mineralogical assemblages, rock typing models, X-ray fluorescence (XRF) data, TOC data and rockmechanics data. The integration of the hyperspectral data with core description, SEM, thin-section, XRF, XRD, rock mechanics and TOC data illustrates relative differences in carbonate volumes that identify Milankovitch cycles, delineates fabric via variations in mineralogical composition of fine laminae, identifies relatively Sr-rich intervals that cannot be distinguished visually, reveals a relationship between total organic content and mineralogy, and facilitates upscaling of SEM and thin-section date to the core scale.
Abstract Robust links between unconventional pore-scale properties, organic matter, and production trends remain unclear, despite numerous pore-scale characterization studies from various petro-technical disciplines. Specifically, a clear and/or widely agreed upon understanding of kerogen-bitumen-porosity relationships is currently lacking. This work explores an interdisciplinary petrographic methodology to link organic pore-associations and habit to geochemistry and, ultimately, petrophysics. The method directly collocates (overlays) high resolution mosaic scanning electron microscopy (SEM) images with reflected white and UV/fluorescent light images (organic matter petrography analysis), enabling the identification of various kerogen maceral types and bitumen within the monochromatic SEM images. Mosaic SEM images are leveraged to help ensure the statistical representativeness of the characterized area. The consistent application of this integrated imaging workflow across various rock types, maturity, and basins has enabled foundational insights into specific organic-matter porosity associations and trends. Introduction Understanding unconventional reservoirs requires examining the porosity and permeability hosted within the mudrock-based (clay and silt-sized grains; includes claystones, mudstones, chalks, siltstones, shales, etc.) stratigraphy of the petroleum system, typically characterized by low porosity and low permeability. Organic porosity, specifically, has been studied for less than a decade, and there is currently a lack of clear understanding of organic porosity development in unconventional mudstone reservoirs (Katz and Arango, 2018). Due to the small nature of the pore sizes, scanning electron microscopy (SEM) is one method used to characterize nanoporosity hosted in the mineral matrices and/or organic matter (Loucks and Reed, 2014). However, SEM is limited in the ability to differentiate between different organic macerals, or individual organic matter constituents, found in the examined organic-rich shale/mudstone. Traditional methods for definitive organic matter determination include organic petrographic analyses using standard incident white light and UV microscopy under oil immersion. Organic petrography is limited to lower magnifications, approximately 50x magnification, compared to the high-magnification possible with SEM, allowing for resolutions up to approximately 2.5 nm/pixel and, correspondingly, pore features of around 5-10 nm.
ABSTRACT Accurate mineralogy modeling and interpretation for thinly bedded formations often requires high-resolution data, usually measured in the laboratory from core samples. However, core measurements are expensive and available only from a limited number of wells in a field. On the other hand, high-resolution logging tools are not sufficient to provide a comprehensive mineralogy characterization. Because other types of logging data are also available from many wells, a high-resolution mineralogy analysis combining low-resolution and high-resolution logging data becomes very attractive. This study focuses on solving for high-resolution on mineralogical compositions of the formation combining pulsed-neutron spectroscopy measurements, image logs, and other conventional log responses. A workflow has been developed with the following major steps:Extract lithology volumetric models from high-resolution image logs combined with other conventional logs; Allocate the modeled mineralogical compositions from lower-resolution geochemical logs into mineral compositions for various lithology types; Obtain a high-resolution mineral model; Perform a quality check by comparing the computed results with core measurements. To demonstrate the method's feasibility and applicability, the proposed workflow was used on a Vaca Muerta log example from the Loma Campana field, which has dramatic variations in mineralogy composition. The processing showed very promising results with the computed high-resolution mineral model matching the core data. This result indicates the proposed method could reproduce the mineral composition with a full vertical variability in a thin-bedded formation that would only be available with extensive core measurements. The approach presented here can offer an integrated, high-resolution formation evaluation for key petrophysical properties, such as formation composition, permeability, porosity, and geomechanical properties. The method provides a great advantage over conventional log interpretation by revealing the full vertical variability of a formation that would otherwise appear insensitive for thin layers with limited resolution and compromised accuracy. The promising results generated from this study demonstrate the feasibility of an integrated core-level petrophysical analysis in a cost-effective and timely manner compared to conventional core measurements.
Amer, AimenAi (Schlumberger) | Sajer, Abdulazziz (Kuwait Oil Company) | Al-Adwani, Talal (Kuwait Oil Company) | Salem, Hanan (Kuwait Oil Company) | Abu-Taleb, Reyad (Kuwait Oil Company) | Abu-Guneej, Ali (Kuwait Oil Company) | Yateem, Ali (Kuwait Oil Company) | Chilumuri, Vishnu (Kuwait Oil Company) | Goyal, Palkesh (Schlumberger) | Devkar, Sambhaji (Schlumberger)
Abstract Producing unconventional reservoirs characterized by low porosities and permeabilities during early stages of exploration and field appraisal can be challenging, especially in high temperature and high pressure (HPHT) downhole conditions. In such reservoirs, the natural fracture network can play a significant role in flowing hydrocarbons, increasing the importance of encountering such network by the boreholes. Consequently, the challenge would be to plan wells through these corridors, which is not always easy. To add to the challenge, well design restrictions dictate, the drilling of only vertical and in minor cases deviated wells. This can reduce the possibility of drilling through sub-vertical fracture sets significantly, and once seismic resolution is considered, it may seem that all odds are agents encountering a fracture network. This article addresses a case where a vertical well is drilled, in the above-mentioned reservoir setting, and missed the natural fracture system. The correct mitigation can make a difference between plugging and abandoning the well or putting it on production. The technique utilized is based on a borehole acoustic reflection survey (BARS) acquired over a vertical well to give a detailed insight on the fracture network 120 ft away from the borehole. Integrating this technique with core and high-resolution borehole image logs rendered an excellent match, increasing the confidence level in the acoustically predicted fracture corridors. Based on these findings new perforation intervals and hydraulic stimulation are proposed to optimize well performance. Such application can reverse the well decommissioning process, opening new opportunities for the rejuvenation of older wells.
Serry, Amr (ADNOC Offshore) | Al-Hassani, Sultan (ADNOC Offshore) | Budebes, Sultan (ADNOC Offshore) | AbouJmeih, Hassan (ADNOC Offshore) | Kaouche, Salim (ADNOC Offshore) | Aki, Ahmet (Halliburton) | Vican, Kresimir (Halliburton) | Essam, Ramy (Halliburton) | Lee, Jonathan (Halliburton)
Abstract This case study demonstrates the role of nuclear magnetic resonance (NMR) T1 spectra, as used to drill complex undeveloped carbonate formations offshore Abu Dhabi. The scope of this project exceeds the traditional porosity-permeability approach to exploit the wealth of information about the rock texture, pore size distribution, flow units and a new methodology of NMR T1 data processing. Evaluation of pore size distributions based on T1 vs. T2 spectra is addressed in two case study wells; one using a 6 ¾-in., and the other a 4 ¾-in. mandrel size for the first time in UAE. Finally, other log-derived permeabilities are presented, together with high-resolution microresistivity image interpretation and production log results in an integrated approach for improved understanding of the petrophysical character of these undeveloped units. NMR T1 measurements are utilized for the first time in the lateral sections as part of a bottomhole assembly (BHA) consisting of a rotary steerable system (RSS), and logging-while-drilling (LWD) sensors, including high-resolution microresistivity imaging, laterolog and azimuthal electromagnetic wave resistivities, thermal neutron porosity, azimuthal density, azimuthal multipole acoustic, ultrasonic caliper and near-bit azimuthal gamma ray. During NMR T1 measurements, the spin relaxation time carries information about the liquid-solid surface relaxation and bulk-fluid relaxation, hence, it is neither affected by rock internal magnetic field gradients nor by differences in fluid diffusivity. Also, T1 logging measurements are influenced by instrument artefacts to a much lesser extent than T2 results, having several advantages over T2, especially regarding polarization and tool motion while drilling. The real-time availability of NMR sourceless porosity measurements significantly improved drilling decisions to place the two case history wells into favourable zones and NMR T1 permeabilities were derived together with acoustic and high-resolution microresistivity image-based permeabilities which were then correlated to production logs. The results indicate that T1 measurements are an effective, practical solution for rock quality evaluation using LWD real-time datasets free from BHA motion and fluid diffusion effects. Comparisons of T1 and T2 logs show that T1 yields equivalent formation evaluation answers, despite its sparser nature. The T1 spectra facilitated improved pore size distribution, permeability estimation and marking of the hydraulic flow units in the heterogeneous, undeveloped Upper Jurassic reservoir units, paving the way for the consideration of T1 logging as a viable, and in some cases superior alternative to T2 logging. This paper presents the multidisciplinary approach used to benchmark and optimize the future field development program.
Franquet, Javier Alejandro (Baker Hughes, a GE company) | Singh, Rudra Pratap (ADNOC offshore) | Diaz, Nerwing (Baker Hughes, a GE company) | Anurag, Atul (ADNOC offshore) | Balooshi, Mohamed Ali (ADNOC offshore) | Jefri, Ghassan Al (ADNOC offshore) | Hosany, Khalid Ibrahim (ADNOC offshore) | Cesetti, Mauricio (ADNOC offshore) | Kindi, Rashid Khudaim (ADNOC offshore) | Zhunussova, Gulzira (Baker Hughes, a GE company) | Bradley, Tom (Baker Hughes, a GE company) | Kirby, Cliff (Baker Hughes, a GE company)
Abstract An injector well drilled from an artificial island in UAE left a non-magnetic fish during well control operations across lower Cretaceous reservoirs below the 9⅝-in. casing shoe, exposing all upper Jurassic reservoirs flow units. The situation was a serious concern to field developing and reservoir integrity as aquifer, gas and many layers of oil reservoirs were connected through the borehole below the fish. It was decided to sidetrack around the fish to intersect the original 8½-in. open-hole section. The sidetrack was accomplished, but the first attempt to intersect the mother hole was unsuccessful. Therefore, an innovative solution was needed for detecting the mother hole to intersect it. A combination of cross-dipole deep shear acoustic, high-resolution induction and orientation wireline measurements were advised. These measurements would be used to update the wellbore survey and to detect acoustic reflections from the mother hole for identifying its relative orientation with respect to the sidetrack hole. Detailed measurement-while-drilling (MWD) wellbore survey analyses were conducted for the original and sidetrack holes beside typical corrections, such as Sag and drillstring interference. The deep shear wave imaging data recorded in the side-track hole was processed at multiple X-dipole polarization directions to detect shear reflection from the mother-hole and back calculate its relative position. The high-resolution induction data could not detect the fish from the sidetrack, but few dipole reflections of the mother hole were detected in two locations. The orientation of the reflectors was consistent with the revised wellbore survey analysis, and this information was used to make the directional drilling corrections required to intersect the mother hole. The use of deep shear wave imaging data to identify a nearby open hole was a non-conventional application of this technology, but it definitely facilitated directional drilling operations to successfully intersect a mother hole that cannot be left uncompleted. After the openhole intersection, a good borehole condition was encountered due to the non-damaging fluid system, allowing the well to be completed as per original plan. Achieving this challenging directional drilling objective was critical for the field development plan of these offshore UAE reservoirs. This case study represents the first documented field experience of using deep shear wave imaging data in the petroleum industry for assisting directional drillers to intersect an open hole mother wellbore after sidetracking a fish.