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Abstract Geothermal District Heating (GDH) doublets in the Central part of the Paris Basin, particularly in the Capital City suburban areas, face two major concerns: The replacement of aging and declining, when not damaged, well infrastructures and productive/injective capacities; GDH doublets density, approaching overpopulation in some areas, which limits well replacement opportunities and clouds new development issues bearing in mind the space limitations in urban areas and the thermal breakthrough/reservoir cooling shortcomings. The Paris suburban Cachan site was considered a relevant candidate for a first implementation of an alternative well architecture design. In March 2018, the second sub-horizontal geothermal injection well, GCAH2, was successfully tested at the Paris suburban Cachan site, thus validating this innovative sub-horizontal well (SHW) architecture, initiated on the previously drilled production well, GCAH1, recorded as a world first with 1000 m 8-1/2 in. open hole horizontal drain. The sub-horizontal drain sections of the wells were drilled using the geosteering technique in place of the usual geometric pre-planned trajectory. Geosteering was successfully used for optimal well placement of the geothermal injection/production doublet. The real-time data was correlated to reservoir model to design and implement a reliable well trajectory and to increase reservoir exposure. Alongside LWD (logging while drilling), advanced near real-time cuttings analysis utilizing elemental and mineralogical measurements and custom software was used to improve decision making while drilling. The integration of chemo-stratigraphy, mud logging, wireline, logging while drilling and production test results improved the correlation between wells, supporting the building of a proper geological model and reservoir characterization.
Kuwait's first smart Level-4 multilateral well was completed in the Burgan reservoir by combining a Level-4 junction with stacked dual-lateral completion with a customized viscosity-independent inflow-control device (ICD), two customized inflow-control valves (ICVs), downhole gauges, a wide-operating-range electrical submersible pump (ESP), suitable wellheads, a tree, and integrated surface panels for real-time data monitoring. The smart multilateral well has assisted in addressing premature water breakthrough, has enhanced water-free oil production, and has facilitated uniform depletion, which results in improved hydrocarbon recovery. The Minagish field in west Kuwait (Figure 1) is a north/south-trending anticline with hydrocarbon contained in six major reservoirs (sandstone and carbonate) ranging in age from Early Jurassic to Late Cretaceous. The Burgan sandstone reservoir lies at the crest of the Minagish field. The lower section of the Burgan sandstone reservoir consists of a braided river system with stacked-channel sand bodies that have very high horizontal and vertical permeability (on the order of a few darcies) and are associated with an underlying active aquifer.
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.
Goraya, Yassar (Adnoc Offshore) | Alfelasi, Ali Saee (Adnoc Offshore) | Khemissa, Hocine (Adnoc Offshore) | Al Dhafari, Bader Mohamed (Adnoc Offshore) | Ashraf, Muhammad (Adnoc Offshore) | Khaled, Islam (Adnoc Offshore) | Al-Mutwali, Omar (Adnoc Offshore) | Okuzawa, Takeru (Adnoc Offshore) | Aki, Ahmet (Halliburton) | Montasser, Ahmed (Halliburton) | Fares, Wael (Halliburton) | ElGammal, Ahmed (Halliburton)
Acquisition of high-resolution images for reservoir characterization from logging-while-drilling (LWD) technologies has historically been limited to water-based mud (WBM) applications. The introduction of LWD ultrasonic technologies means high-resolution images and the associated analysis are now available in both WBM and oil-based mud (OBM) applications.
This paper details the first deployments of a 4¾-in. LWD ultrasonic imaging service in a mature field, offshore Abu Dhabi, and the assessment of images in both WBM and OBM wells. The 4¾-in. ultrasonic tool combines both borehole size and shape measurements with high-resolution radius and reflection amplitude images. The ultrasonic sensor uses four transducers that operate in a pulse-echo mode. By firing simultaneously, the transducers provide a total of 2,000 travel time and reflection amplitude measurements each second, enabling the creation of high-resolution images, even at high-logging speeds. The methodology described was used to evaluate the suitability of the LWD ultrasonic measurements to enhance reservoir understanding, along with LWD azimuthal formation density and azimuthal high-resolution resistivity image measurements in WBM applications.
The 4¾-in. ultrasonic borehole imaging technology was deployed while drilling with OBM/WBM to acquire ultrasonic images to capture the subtle geological features that often control the reservoir properties, but whose characterization was challenging previously due to technology limitations. The long lateral was logged with ultra-sonic imaging while drilling through Cretaceous carbonates, traversing through different layers going up and down in stratigraphy; showcasing subtle variations with complementing images that helped understand the vug distribution, bioturbation, faults, and dissolution seams, in addition to the bedding boundaries.
High-resolution borehole shape analysis was performed to understand the impact of stresses on the well trajectory, made possible with the high-definition, multisector images. The resolution of the reflection amplitude images, in particular, enables identification of drilling-induced features on the surface of the borehole, highlighting the measurement's value in understanding the impact of the bottom hole assembly (BHA) on the quality of the wellbore. The travel time measurements provide detailed evaluation of the borehole size and shape, with the three-dimensional (3D) visualization of the wellbore illustrating the ability of the service to identify borehole enlargement and breakout. These findings demonstrate the suitability of the service to address wellbore stability issues in real time.
This paper details the first use of the ultrasonic service in Abu Dhabi. Comparison of images from the new ultrasonic imaging service with established LWD technologies highlights the suitability of the radius and reflection amplitude images to provide enhanced formation evaluation analysis in both WBM and OBM applications. Log examples show the high-resolution images are able to identify bedding features and fractures and provide assessment of borehole size and shape for wellbore stability evaluation.
Horstmann, Mathias (Schlumberger) | Shrivastava, Chandramani (Schlumberger) | Denichou, Jean-Michel (Schlumberger) | Halset, Gjertrud (Vår Energi) | Firinu, Mauro (Vår Energi) | Colombo, Federica (Vår Energi) | Sarkar, Subhadeep (Schlumberger) | Hassan, Mirza Baig (Schlumberger) | Nyboe, Sigurd (Schlumberger) | Sikdar, Koushik (Schlumberger)
The Norwegian oil and gas industry (O&G) operates nowadays in more demanding and sensitive drilling environments while it approaches more complex reservoirs facing multiple challenges, both technically and environmentally. Not allowing shortcuts to success, clearly any technology helping to mitigate risks, increasing efficiency and reliability should be embraced. Especially as in parts the public perception towards O&G is more critical, clear corporate governance towards risk reduction by process or technology is more than adequate, assuring to comply with the general guideline of reducing critical activities and operations, such as radioactive source handling and logging with it.
A recent operation on the Norwegian Continental Shelf (NCS) is an excellent example of combining local knowledge with fit-for-purpose technology to minimize timescales and risks while improving efficiency and formation evaluation in an extended reach horizontal well construction to further develop the Marulk field in the Norwegian Sea.
This was achieved through the first global application of geosteering operations using a comprehensive real-time (RT) data acquisition governed by a sourceless "green bottom hole assembly (BHA)" in oil-based mud (OBM) environment. Including most notably a novel high-definition dual physics OBM imager and in the logging-while-drilling (LWD) arena unique accelerator-based radioisotope-free bulk density, neutron, sigma and elemental capture spectroscopy measurements, deployed along with azimuthal ultra-deep electro-magnetic (EM) reservoir mapping technology. All to provide a complete reservoir and geological description of the Cretaceous sandstones deposited in turbidite fans with moderate to good quality.
The utilization of this sourceless LWD technology as the kernel acquisition empowers the well construction to be actively steered not only by formation qualities but also by the fluid characteristics in real-time, basically providing information about the structure, rock properties and in-situ movable fluids.
The quantitative evaluation of petrophysical logs for hydrocarbon saturation had a good match with reservoir delineation and maps from deep EM measurements, confirming the net hydrocarbon bearing producible sands. Surface mud gas data was also analyzed, and its integration with petrophysical interpretation indicated the presence of heavier hydrocarbon fractions towards the toe of the well. A high-resolution sand count interpretation from dual physics borehole imaging tool confirmed the maximum net reservoir potential. The well is currently producing above the predicted rate.
The case studied is a great example where a strong interaction between professionals both in the planning and execution phase making use of available and most suitable technologies. Together with a positive mind-set and a winning attitude it resulted in a better understanding of the complexity of the reservoir and finally placing the lateral in the best evaluated reservoir facies.
The Operator and the license partnership have set an extremely high ambition for recovery from the Johan Sverdrup field, even before a barrel of oil has been produced. How is this possible? This paper describes the characteristics of the reservoir, as well as early assessments and investments for improved oil recovery (IOR) to ensure flexibility. In addition, data acquisition, reservoir monitoring, new technologies and digitalisation, as well as new ways of working are addressed. This will be the key enablers for a recovery of more than 70% of the field’s oil resources.
Johan Sverdrup is the third largest oil field on the Norwegian Continental Shelf (NCS) with a recoverable volume range of 2,2 to 3,2 billion b.o.e. The reservoir is characterized by excellent reservoir properties with a strongly undersaturated oil. The primary drainage strategy is water flooding, including re-injection of all produced water, supplemented by water-alternating-gas (WAG) injection at the end of the oil production plateau. The field came on stream in October 2019.
Going back to the early stages of the Johan Sverdrup field development, it was obvious from the start that this would be an independent development solution with a long lifetime. Given the excellent reservoir, this was considered as a unique opportunity to plan for a high resource exploitation, and make sure that future business opportunities in this context could be utilized in a technical and economically attractive way.
A very early screening was conducted to investigate which IOR measures should be further matured. With subsurface evaluations as the base, this maturation also included assessments on technical feasibility and potential implications for development solutions. The objective was to ensure sufficient flexibility in early field design. It also implied that the Johan Sverdrup license had to consider pre-investments prior to any implementation decision.
Data acquisition and reservoir monitoring strategies were also started early on, which e.g. led to a full field Permanent Reservoir Monitoring (PRM) decision, with installation starting summer 2019. This gives a baseline for parts of the field before production start, and when completed in 2020 it will be the world’s largest fiber based PRM system. Fiber optics are also installed in the wells. In addition, a dedicated observation well is part of the development plan. The idea is that PRM and fiber data results, in addition to repeated logging in the observation well, will be key information to evaluate business cases for future IOR or new technology measures.
Digitalisation has also been a key aspect of this, and several subsurface-focused digitalisation initiatives have been implemented during the field development, giving the operator the opportunity to implement new ways of working and enabling new ways of cooperation in the partnership as data and applications are shared within the owner group in a digital setting. The overall objective of digitalisation in this context is to further optimize the analysis and management of the Johan Sverdrup reservoir – and hence value of the Johan Sverdrup field – for the license owners.
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.
Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Al-Otaibi, Fahad (Kuwait Oil Company) | Kumar, Joshi Girija (Kuwait Oil Company) | Tiwary, Devendra (Kuwait Oil Company) | Al-Ashwak, Samar (Kuwait Oil Company) | Dzhaykiev, Bekdaulet (Baker Hughes, a GE Company) | Shinde, Neha (Baker Hughes, a GE Company) | Hardman, Douglas (Baker Hughes, a GE Company) | Noueihed, Rabih (Baker Hughes, a GE Company) | Gadkari, Shreerang (Baker Hughes, a GE Company)
Abstract The complex nature of the reservoir dictated comprehensive formation evaluation logging that was typically done on wireline. The high angle designed for maximum reservoir exposure, high temperature, high pressure (HTHP), differential reservoir pressure and wellbore stability challenges necessitated a new approach to overall formation evaluation. The paper outlines Formation Evaluation strategy that reduced risk, increased efficiency and saved money, while ensuring high quality data collection, integration and interpretation. After review of all risks, a decision to utilize Managed Pressure Drilling (MPD) for wellbore stability, Logging While Drilling (LWD) to replace wireline and Advanced Mudlogging Services was implemented. The Formation Evaluation team utilized LWD resistivity, neutron, density and nuclear magnetic resonance logs supplemented with x-ray diffraction (XRD), x-ray fluorescence (XRF) and advanced mud gas analysis to ensure comprehensive analysis. The paper outlines workflows and procedures necessary to ensure all data from LWD, XRF, XRD and mud gas are integrated properly for the analysis. Effects of Managed Pressure Drilling on mud gas interpretation as well as cuttings and mud gas depth matching are addressed. Depth matching of all data, mud gasses, cuttings and logs are critical for detailed and accurate analysis and techniques are discussed that ensure consistent results. Complex mineralogy due to digenesis and effect of LWD logs are evident and only reconciled by detailed XRF and XRD data. The effects of some conductive mineralogy are so dramatic as to infer tool function compromise. The ability to determine acceptable tool response from tool failures eliminates unnecessary trips and leads to efficient operations. The final result of the above data collection, QC and processing resulted in a comprehensive formation evaluation interpretation of high confidence. Finally, conclusions and recommendations are summarized to provide guidelines in Formation Evaluation in similar challenging highly deviated, HTHP, complex reservoir environments on land and offshore.
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.
Thakur, Parmanand Dhermeshwar (ADNOC Onshore) | Agnihotri, Praveen (ADNOC Onshore) | Deng, Lichuan (Baker Hughes, a GE Company) | Soliman, Ahmed M. (Baker Hughes, a GE Company) | Kieduppatum, Piyanuch (Baker Hughes, a GE Company) | Fernandes, Warren (Baker Hughes, a GE Company)
Abstract Logging-While-Drilling (LWD) has incorporated almost all wireline-equivalent technology with the added advantage of logging high-angle and horizontal wells with reduced rig time, critical for cost optimization efforts. LWD measurements are affected by a rugged drilling environment, and logging interpretation with a wireline mindset leads to erroneous results. Identifying measurement artefacts from real formation information is critical for reliable log analysis. This publication discusses the most common effects of drilling dynamics and environments on LWD logs that were observed during logging and drilling wells in cretaceous carbonate reservoirs in an Abu Dhabi onshore field. Log data from more than one hundred wells are reviewed to identify several interesting effects due to bottom-hole-assembly (BHA) design, BHA driving mechanism (Rotary steerable system versus mud motor), tool eccentricity, well angle, mud properties, differential invasion, borehole condition, formation fluid properties and lithology. In a few instances, some of these effects occur simultaneously, complicating the log response. These phenomenons are discussed in detail with actual examples and compared to offset wells and response modellings. The rugged logging environment and limited formation damage due to invasion provide a unique opportunity to obtain additional insight about reservoir behavior, especially when compared to wireline data in an offset well or in the same well. Pre-job planning and modelling can use these phenomena for getting additional information about dynamic reservoir behavior. This paper highlights a few such applications. This paper explains the impact of a dynamic drilling environment on LWD measurements and serves as a ready reference to identify measurement artifacts from real formation information. It is helpful as a guidebook for log analysts, geologist, geo-steering engineers and other non-specialists to identify LWD measurement artefacts.