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Serry, Amr M. (ADNOC Offshore) | Al-Hassani, Sultan D. (ADNOC Offshore) | Ahmed, Shafiq N. (ADNOC Offshore) | Khan, Owais A. (ADNOC Offshore) | Aboujmeih, Hassan F. (ADNOC Offshore) | Zakaria, Hasan (ADNOC Offshore) | Pippi, Olivier P. (ADNOC Offshore) | Salim, Israa A. (Schlumberger) | Abdel-Halim, Amro (Schlumberger) | Donald, Adam (Schlumberger)
Abstract Faulting is one type of structural trap for hydrocarbon reservoirs. With more and more fields moving toward the brownfield or mature operations stage of life, the opportunity to target bypassed or attic oil in the vicinity of bounding fault(s) is becoming more and more attractive to operators. However, without an effective logging-while-drilling (LWD) tool to locate and map a fault parallel to the well trajectory, it has been challenging and potentially high risk to optimally place a well to drain oil reserves near the fault. Operators often plan these horizontal wells at a significant distance away from the mapped fault position to avoid impacts to the well construction and production of the well. Often, the interpreted fault position, based on seismic data, can have significant lateral uncertainty, and uncertainties attached to standard well survey measurements make it challenging to place the well near the fault. This often results in the wells being placed much farther from the fault than expected, which is not optimal for maximizing recovery. In other cases, due to uncertainty in the location of the fault, the wells would accidentally penetrate the side faults and cause drilling and other issues. Conventional remote boundary detection LWD tools do not assist with locating the fault position, as they only detect formation boundaries above or below the trajectory and not to the side. In this paper, the authors propose a novel approach for mapping features like a fault parallel to the well trajectory, which was previously impossible to map accurately. This new approach utilizes a new class of deep directional resistivity measurements acquired by a reservoir mapping-while-drilling tool. The deep directional resistivity measurements are input to a newly devised inversion algorithm, resulting in high-resolution reservoir mapping on the transverse plane, which is perpendicular to the well path. These new measurements have a strong sensitivity to resistivity in contrast to the sides of the wellbore, making them suitable for side fault detection. The new inversion in the transverse plane is not limited to detecting a side fault; it can also map any feature on the transverse plane to the well path, which further broadens the application of this technology. Using the deep directional resistivity data acquired from a horizontal ultra-ERD well recently drilled in the Wandoo Field offshore Western Australia, the authors tested this approach against the well results and existing control wells. Excellent mapping of the main side fault up to 30 m to the side of the well was achieved with the new approach. Furthermore, the inversion reveals other interesting features like lateral formation thickness variations and the casing of a nearby well. In addition, the methodology of utilizing this new approach for guiding geosteering parallel to side fault in real time is elaborated, and the future applications are discussed.
Abstract During well planning, drillers and petrophysicists have different principle objectives. The petrophysicist’s aim is to acquire critical well data, but this can lead to increased operational risk. The driller is focused on optimizing the well design, which can result in compromised data quality. In extreme cases, the impact of well design on petrophysical data can lead to erroneous post-well results that impact the entire value-chain assessment and decision making toward field development. In this paper, we present a case study from a syn-rift, Upper Jurassic reservoir in the Norwegian Sea where well design significantly impacted reservoir characterization. Three wells (exploration, appraisal, and geopilot) are compared in order to demonstrate the impact of overbalanced drilling on well data from both logs and core. Implications for reservoir quality assessment, volume estimates, and the errors introduced into both a static geomodel and dynamic reservoir simulation are discussed. This case study highlights the importance of optimizing well design for petrophysical data collection and demonstrates the potential for value creation. Extensive data collection was initially carried out in both exploration and appraisal wells, including full sets of logging while drilling (LWD), wireline logging, fluid sampling, and extensive coring. Both wells were drilled with considerable overbalanced mud weights due to the risk of overpressured reservoirs in the region. The log data was subsequently corrected for significant mud-filtration invasion, with calibration to core measurements guiding the interpretation. Geological and reservoir models were built based on results from the two wells, and development wells were planned accordingly. A thorough investigation of core material raised suspicion that there could also be a significant adverse effect of core properties resulting from overbalanced drilling. The implications were so significant for the reservoir volume that a strategic decision was made to drill a geopilot well close to the initial exploration well, prior to field development drilling. The well was drilled six years after the initial exploration phase with considerably lower overbalance. Extensive well data, including one core, were acquired. The recovered core was crucial in order to compare the reservoir properties for comparable facies between all three wells. The results from the core demonstrate distinctly different rock quality characteristics, especially at the high end of the reservoir quality spectrum. Results of the core study confirmed the initial hypothesis that overbalanced drilling had significantly impacted the properties of the core as well as the well logs. The study concluded that the updated reservoir model properties would significantly increase the in-place volumes compared to the pre-geopilot estimate. This study shows how well design adversely affected petrophysical measurements and how errors in these data compromised geological and reservoir models, leading to a suboptimal field development plan that eroded significant value. This example provides a case study that can be used to improve the well design so that petrophysicists and drillers can both be part of the same value creation result. Future work will include further laboratory investigations on the effects of high overbalanced drilling on core and possible “root causes” for compromised core integrity.
Jacques, Antoine (TOTAL SE) | Jaffrezic, Vincent (TOTAL SE) | Brouard, Benoit (Brouard Consulting) | Ahmed, Shafiq (ADNOC Off Shore) | Serry, Amr Mohamed (ADNOC Off Shore) | Nguyen, Raymond (ADNOC Off Shore) | Bigno, Yann (ADNOC Off Shore)
Abstract In current economic and environmental contexts, the optimization of long, horizontal well completion and the maximization of individual well performance are becoming increasingly important. The challenge is to be able to start improving the production efficiency while designing an adapted completion for each well without compromising the project economy. The cost-effective formation evaluation technique described in this paper allows rapid identification of dynamic heterogeneities along the reservoir after the drilling of a horizontal well. This key information then can be used to optimize well completion and treatment. This new approach, called WTLog, combines well testing and logging techniques and was introduced initially for the optimization of unconventional well completion (Jacques et al., 2019 and Manivannan et al. 2019). The log begins by circulating a low-viscosity liquid that can be injected in the formation through the mud cake. The brine circulation operation is run at the end of the drilling phase, after reaching TD of the drain while maintaining a constant wellhead pressure at the wellhead. The constant pressure control can be applied without a specific additional choke device when Managed Pressure Drilling (MPD) is used to drill the formation section. The inlet and outlet flowrates are measured accurately, and their difference corresponds to the apparent formation-injection rate. The depth of the interface between the two liquids inside the borehole is estimated from the flowrates and pressure measured at the wellhead. Combining these data allows derivation of the low-viscosity/liquid-injection profile along the open hole. A permeability log then can be derived by inversion. Well Test Logging has been applied successfully for the first time on two horizontal wells in a conventional carbonate reservoir. The interpretation results were benchmarked to static conventional openhole logs and validated against the data log obtained by the dynamic production log tool (PLT) performed after well start-up. This technique opens new perspectives for optimizing well completion in these carbonate-fractured formations for which porosity logs might not be a good permeability indicator and where conductive fractures seen on image logs are not always indicative of future production.
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.
Wells drilled with nitrified drilling fluids require a solution for the transmission of measurement-while-drilling (MWD) surveys, bidirectional communication with rotary-steerable systems (RSSs), and transmission of MWD and and logging-while-drilling (LWD) measurements of downhole temperature and annular pressure for surface choke adjustments. Results from a well recently drilled into an underpressured reservoir in southern Mexico provided an opportunity to demonstrate the applicability of wired drillpipe (WDP) to deliver the required measurements and maintain the proper directional control while keeping the well fluids under control. This paper describes how WDP and managed-pressure drilling (MPD) enabled an operator to drill a severely depleted reservoir with an inverse-emulsion mud mixed with nitrogen delivered through a drillpipe-injection system. This field has a complex structure divided by a salt intrusion into northern and southern portions. Six reverse faults oriented in different directions are involved in this structure.
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.
Singh, Maniesh (ADNOC osnhore) | Al Arfi, Saif (ADNOC osnhore) | Boyd, Douglas (ADNOC) | Gerges, Nader (ADNOC) | Fares, Wael (Halliburton) | Clegg, Nigel (Halliburton) | Aki, Ahmet (Halliburton) | Diab, Emad (Halliburton) | Pandey, Vikram (ADNOC onshore) | Mansoori, Maisoon M. Al (ADNOC onshore) | Seddik, Ibrahim A. (ADNOC onshore) | Reddy, Rathnakar (ADNOC onshore)
ADNOC's limestone reservoirs suffer from the phenomena of injection water traveling preferentially at the top of the reservoir placing injection water above oil held there by capillary forces. Horizontal wells placed below areas of water override, cause the water above to slump unpredictably, increasing water cut and eventually killing the horizontal. Ultra Deep Directional Electromagnetic (EM) Logging While Drilling (LWD) tools provide the measurements to identify and map these water zones, improving reservoir management and design optimal well placement.
1D & 2D EM inversion modeling was conducted on two of ADNOC's largest oil producing reservoirs to evaluate the ability of an Ultra Deep Directional EM LWD Resistivity tool to identify water slumping in the presence of formation bed resistivity contrasts and predict depths of reliable detection (DOD) under various well trajectory scenarios. The inversion was run using depth of inversions up to 150 ft, the maximum expected vertical distance of tool to injection water. Modeling provided an optimized tool configuration (frequency, transmitter-receiver spacing's) to meet objectives. The inversion results further provided guidance for Geosteering, Geomapping and Geostopping decisions.
The inversion results in these reservoirs indicated that the Ultra Deep resistivity tool has a DOD of 50-150 ft to pick reservoir tops and water slumping or non-uniform waterfront boundaries. The real-time inversion will optimize landing and drilling long horizontal section to increase net pay for production and even through sub-seismic faults, measuring changes in the reservoir fluid distribution, reduce drilling risk and exceed well production life. This information will aid in updating static model with water flood areas, reservoir tops, faults and structure, designing better infill well spacing and trajectories within bypass oil regions, designing proactive and not reactive smart well completions to delay or reduce water production and ultimately extended plateau and improve ultimate recovery factor. Furthermore, it will aid resistivity mapping of underlying or overlying reservoirs for future development plans.
The encouraging results of this study confirmed to move forward with a field trial in these challenging reservoirs for better reservoir and fluid characterization and its management.
Molua Lyonga, Sammy (Schlumberger) | Maalouf, Janine (Schlumberger) | Shrivastava, Chandramani (Schlumberger) | Ali, Humair (Schlumberger) | Shasmal, Sudipan (Schlumberger) | Khemissa, Hocine (Abu Dhabi National Oil Company) | Goraya, Yassar (Abu Dhabi National Oil Company) | Muhammad, Ashraf (Abu Dhabi National Oil Company) | Al Dhafari, Bader Mohamed (Abu Dhabi National Oil Company) | Khaled, Islam (Abu Dhabi National Oil Company) | Alfelasi, Ali Saeed (Abu Dhabi National Oil Company)
Carbonate reservoirs show huge variations in petrophysical properties resulting from leaching/dissolution, fracturation, cementation and or dolotomization. Permeability anisotropy is one property which if understood properly, helps at different stages of reservoir development especially in cases of substantial density difference between fluids; primary production below the bubble point, gas cycling, gas/or water coning etc. Where the anisotropy is severe, it can also influence fluid injection and production rates. For carbonates, microporosity and fractures make it very challenging to relate porosity and lithofacies to permeability. In addition, thin bedded layers that can enhance production maybe unidentifiable because of the coarse nature of conventional logs, at least using Logging While Drilling (LWD) in wells drilled with Oil base muds (OBM) until recently.
The recently introduced LWD dual physics (ultrasonic and resistivity) imaging service with a resolution of 0.2 inch now opens the door to capture heterogeneity using high definition images at very fine scales in OBM that was not possible earlier. High definition borehole images are used to isolate and quantify secondary porosity features like vugs. The density of the vugs per unit length is plotted and correlated to pretest mobility which is a direct indicator to flowrate.
The vug density shows a positive correlation with pretest mobility. The high-resolution images also show intervals where the mobility is enhanced as a result of the influence of thin bed boundaries or where the mobility is lowered because of dense features like stylolytes. The vug density-mobility (vd-m) plot completes a picture of pretest mobility trends limited by the distance between pressure points stations. With the vd-m, more refined facie analyses are possible, together with a better understanding of the permeability distribution across a well.
The effectiveness of a more refined picture of the permeability heterogeneity is seen in the Lower Cretaceous carbonates in an offshore Middle East well. Known porosity variations from core analysis and petrographic images attest to the heterogeneity seen in the vd-m correlation logs. The resolution of vd-m is helpful in understanding the productivity and injection capabilities of such carbonate reservoirs, for example, for optimizing ICD design. Further integration with other data (advanced mud gas analysis) and work processes (geosteering) provide a way of identifying fluid changes in wells, identifying different litho-types and aid in justifying critical geosteering decisions.
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.