bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Application of Epoxy Resin to Eliminate Sustained Casing Pressure Without Costly Downhole Well Intervention - Case History from East Kalimantan, Indonesia
Authors: Guna Yogi Adi , Frank Michael , Rochman Novianto , Putra Thomas Herdian Abi , Irvan Mohammad , Fitriansyah Alfatah , Kurniawan Ibnu
Published: December 2021

An operator recorded 1100 psi of sustained casing pressure between a 9-5/8" casing and a 3.5" production tubing annulus seven days after the cementing operation was completed for the 3.5" production tubing. A production logging run was performed, and results indicated gas was flowing from a zone 86 feet below the 9-5/8" casing shoe. As per the operator's standard, such a situation suggests subsequent well completion operations cannot be processed and must be remediated. The most common solution for such situations is to perforate and squeeze to ensure zonal isolation in the zone from which the gas is flowing. Due to the slim tubing size this operation can be difficult, and there exists a high risk of leaving set cement inside the 3.5" tubing. Furthermore, drilling would require extensive time with a coil tubing unit and in the worst case could lead to the loss of the well.

To provide a dependable barrier for long term well integrity, a novel approach consisting of epoxy resin was discussed. A highly ductile, solids-free resin was designed and tailored to seal off communication from the gas source to surface. The void space in the annulus was estimated to be less than 5 bbl. An equipment package was prepared to mix and pump the resin into the annulus. Resin was pumped through the wellhead casing valve using a hesitation squeeze technique with the maximum surface pressure limited to 3000 psi. Once all resin was pumped, the casing valve was closed to allow enough time for the resin to build compressive strength.

The job was planned to be performed in multiple stages consisting of smaller volumes. The job was completed in two stages, and the annular pressure was reduced. On the first job, 1 bbl of resin was mixed and injected into the annulus. The pressure build up was decreased from 550 psi per day to 27 psi per day. To lower the annular pressure further, a second resin job was performed using 0.35 bbl resin volume, which further reduced the annular pressure build up to 25 psi within 3 days. No further stages were performed as this was considered a safe working pressure for the well owner. After 2 months no annular pressure was observed.

The application of this tailored resin helped to improve the wells integrity under these circumstances in this high-pressure gas well. Epoxy resin with its solid-free nature and deep penetration capabilities helped to seal off a very tight flow path. This application of pumping resin through the wellhead to overcome annular gas pressure can be an option when the flow path is strictly limited, or downhole well intervention is very difficult and risky.
Innovative Liner Hanger System Designed for Operational Benefits in Harsh Environments
Authors: Hashmi Ahmad Atef , Riskiawan Arris R , Pedreira Jose Eduardo , Al Marghalani Ahmad
Published: December 2021

Since the beginning of drilling for oil, improving efficiency and reducing the cost of hydrocarbon recovery have been key issues when designing a well. Since then, new methods and techniques have developed the industry. One of the most critical events in the oil and gas industry was the invention of the liner hanger.

Since Liner Hangers are utilized as the primary solution to wellbore construction, they have been designed with such requirements in mind. This paper will deliver an insight to an innovation life cycle where a stakeholder collaborated together to successfully deliver, plan and complete the first 15,000 PSI, 400 °F high pressure- high temperature (HPHT) Liner Hanger designed to overcome the operational obstacles that conventional liner hangers have when deployed with Multistage Frac (MSF) completion systems but still allows for successful operations in cemented completions.

This liner hanger technology has been run in different parts of the world and has proven since the beginning that with all the features included in the designed stages.
Integration Applications of Image and Sonic Data in the Fault-Dominated Carbonate Reservoir in Tarim Basin
Authors: Zhang Yu , Xiao Honglin , Zhang XiaoMing , Liu Haidong , Liu Bo , Wang Wei , Li Shenzhuan , Wei Guo , Liu Xunqi , Yu Daiguo , Wu Jinlong , Zhao Xianran
Published: December 2021

Carbonate reservoir is one of the most complex and important reservoirs in the world. It was confirmed that the slip-strike fault played a crucial role in the fault-dominated carbonate reservoir in Tarim basin. It is challenging to evaluate this kind of reservoir using the open-hole log or seismic data. Identifying and characterizing the fault-dominated carbonate reservoir were the objectives of this case study.

High-definition borehole resistivity image and dipole sonic logs were run in several wells in the research area. It was revealed the detail features of the fault-dominated carbonate reservoir, such as natural fractures, faults or breccias. Compared with the typical geological model of strike-slip faults and outcrop features, the characteristics of the breccia zone and the fracture zone in the strike-slip fault system were summarized from the borehole image interpretation. A unique workflow was innovated with the integration of image and sonic data. Breccias and fractures were observed in the borehole image; and reflections or attenuations in Stoneley waveforms can provide indicating flag for permeable zones. Integrated with the other related geological data like mud logging or cores, the best pay zones in the fault-dominated carbonate reservoir were located.

The characteristics of the strike-slip fault was revealed with the integration of the full-bore formation microimager and dipole shear sonic imager data. The fault core was a typical breccia zone with strong dissolution, which showed good potential in permeability, but it was found that some fault cores were filled with siliceous rock or intrusive rock. The features of the fillings in the fault zone were described based on the image and sonic data. The side cores or geochemical spectroscopy logs data helped to determine the mineralogy of the fillings. The fracture zones had clear responses in the image and sonic data too. The un-filled or half-filled breccia zone were the best zones in the fault-dominated carbonated reservoir. The details of the fault-dominated carbonate reservoir could be used in the future three-dimensional geological modelling.
Litho-Based Pore Scale Waterflooding in Carbonate Reservoirs: A Holistic Approach to Predict Displacement Efficiency
Authors: Ibrahim Mahmoud Mohamed , Bowden Stephen Andrew
Published: December 2021

Grainstones deposited on carbonate ramps are excellent petroleum reservoir formations and are important for energy needs. Waterflooding is routinely used to augment oil recovery and many carbonate fields have long production histories. Future management of these "mature" assets requires knowledge of how oil production can be sustained and enhanced but requires understanding the pore-scale displacement processes. Despite decades of waterflooding in carbonate oilfields a plausible displacement efficiency prediction is not yet trivial. To evaluate waterflooding economics, it is crucial to know the residual oil saturation (Sor) and where oil is entrapped by capillarity in the reservoir. Microfluidic waterflooding experiments provide a means to visualize pore-scale phenomena within different carbonate minerals (calcite, dolomite, and gypsum) and petrographic textures, to estimate microscopic displacement efficiency. By using analogues of carbonate ramp reservoir-lithologies (in terms of texture, unstructured-irregular pore networks and varied mineralogical compositions) realistic evaluations of displacement efficiency were determined for different mineralogical compositions. The quantitative test results matched closely Arab formation SCAL published data.

It was determined that multi-mineralic grainstones undergoing waterflood likely experience contemporaneous imbibition and drainage, giving rise to complex multiphase flow due to the existence of different states of wettability. This wettability contrast induces "capillary jumps" across wettability-boundaries at the interface between different lamina or textures. These "capillary leaps" account for increase in oil recovery as they occur but leave behind bypassed oil. Consequently poly-mineralic arrangements have a lower oil recovery compared to mono-mineralic cases.

It was observed that distinct Sor are achieved at different injected pore volumes, despite sharing similar porosity & permeability, thus the relationship between Sor and porosity/permeability is weak. Thus, predicting waterflooding efficiency requires the different carbonate minerals Sor to be incorporated in dynamic simulation.
Remediating a Landslide Affected Well for Subsequent Abandonment - Challenges Overcome and Solutions Applied
Authors: Cirstian Felicia , Sauter Jason Patrick , Vintila Constantin , Albulescu Gheorghe , Badescu Cosmin Constantin , Ene Maximilian
Published: December 2021

Control/Tracking Number 21 ADIP-P-4946-SPE

Abstract Description

This paper will present a case study to describe the well integrity complications of an onshore gas well in Romania affected by a landslide event, the challenges overcome during the land consolidation/excavation around the well, and the remediation solution of the well's casings. After being severely affected by a landslide, the subject well stopped production having a surface deviation from the original position of 5m and a landslide plane at cca 25m. The primary scope of the project was to restore the integrity of the well in order to safely abandon the well so that people and environment were not exposed to risk or danger.

The project was elaborated through a collaborative effort of multidisciplinary teams including company personnel, such as well integrity engineers, completion engineers, geologists, abandonment team members, civil engineers, HSSE and construction, as well as several service providers. As part of the Phase to consolidate the well's surrounding area, additional risk mitigations were identified through HAZID workshops and implemented, such as creating gas drainage shafts, utilizing ATEX equipment and cold cutting tools for casings, tools, and organizing Rescue People Services. These elements and more aspects were elements of safety included in the project to better assure the success.

The project has several milestones, the first being the consolidation of the well surroundings using 33 cement pillar rings with a total diameter of 8m and depth of 32m. A gas relief column was necessary to ensure the gas infiltration was exhausted from the soil. Once the ring was formed around the well, the excavation commenced inside the ring, avoiding impact with the conductor pipe of the well. This activity posed notable HSSE challenges, requiring solutions derived from HAZID workshops based on evaluations of the various discipline teams and certified parties. Following the excavation, the planned casing remediation included cold cutting the casing using diamond encrusted equipment, due to the gas presence at the well area. Casing restoration was planned for use of bolts to reconnect the casings, thus preventing welding.
Simulation of Immiscible WAG Experiments Performed in Carbonate Rocks: The Impact of Heterogeneity on Hysteresis Phenomenon
Authors: Alnuaimi Latifa Obaid , Sohrabi Mehran , Aghabozorgi Shokoufeh , Alshmakhy Ahmed
Published: December 2021

Simulation of Water-Alternating-Gas (WAG) Experiments require precise estimation of hysteresis phenomenon in three-phase relative permeability. Most of the research available in the literature are focused on experiments performed on sandstone rocks and the study of carbonate rocks has attracted less attention. In this paper, a recently published hysteresis model by Heriot-Watt University (HWU) was used for simulation of WAG experiments conducted on mixed-wet homogenous carbonate rock.

In this study, we simulated immiscible WAG experiments, which were performed under reservoir conditions on mixed-wet carbonate reservoir rock extracted from Abu Dhabi field by using real reservoir fluids. Experiments are performed with different injection scenarios and at high IFT conditions. Then, the results of the coreflood experiments were history matched using 3RPSim to generate two-phase and three-phase relative permeability data. Finally, the hysteresis model suggested by Heriot-Watt University was used for the estimation of hysteresis in relative permeability data. The performance of the model was compared with the experimental data from sandstones to evaluate the impact of heterogeneity on hysteresis phenomenon.

It was shown that the available correlations for estimation of three-phase oil relative permeability fail to simulate the oil production during WAG experiments, while the modified Stone model suggested by HWU provided a better prediction. Overall, HWU hysteresis model improved the match for trapped gas saturation and pressure drop. The results show that the hysteresis effect is less dominant in the carbonate rock compared to the sandstone rock. The tracer test results show that the carbonate rock is more homogenous compared to sandstone rock. Therefore, the conclusion is that the hysteresis effect is negligible in homogenous systems.
Zipper Fracturing of Horizontal Cluster Wells: Game Changing Unconventional Fracturing in UAE
Authors: Wu Yang , Sorensen Ole , Lazreq Nabila , Luo Yin , Bukovac Tomislav , Arali Vaishak
Published: December 2021

Following the increase in demand for natural gas production in the United Arab Emirates (UAE), unconventional hydraulic fracturing in the country has grown exponentially and with it the demand for new technology and efficiency to fast-track the process from fracturing to production. Diyab field has historically been a challenging field for fracturing given the high-pressure/high-temperature (HP/HT) conditions, presence of H2S, and the strike-slip to thrust faulting conditions. Meanwhile, operational efficiency is necessary for economic development of this shale gas reservoir. Hence "zipper fracturing" was introduced in UAE with modern technologies to enable both operational efficiency and reservoir stimulation performance.

The introduction of zipper fracturing in UAE is considered a game changer as it shifted the focus from single-well fracturing to multiple well pads that allow for fracturing to take place in one well while the adjacent well is undergoing a pumpdown plug-and-perf operation using wireline. The overall setup of the zipper surface manifold allowed for faster transitions between the two wells; hence, it also rendered using large storage tanks a viable option since the turnover between stages would be short. Thus, two large modular tanks were installed and utilised to allow 160,000 bbl of water storage on site. Similarly, the use of high-viscosity friction reducer (HVFR) has directly replaced the common friction reducer additive or guar-based gel for shale gas operation. HVFR provides higher viscosity to carry larger proppant concentrations without the reservoir damage, and the flexibility and simplicity of optimizing fluid viscosity on-the-fly to ensure adequate fracture width and balance near-wellbore fracture complexity. Fully utilizing dissolvable fracture plugs was also applied to mitigate the risk of casing deformation and the subsequent difficulty of milling plugs after the fracturing treatment. Furthermore, fracture and completion design based on geologic modelling helped reduce risk of interaction between the hydraulic fractures and geologic abnormalities.

With the application of advanced logistical planning, personnel proficiency, the zipper operation field process, clustered fracture placement, and the pump-down plug-and-perforation operation, the speed of fracturing reached a maximum of 4.5 stages per day, completing 67 stages in total between two wells placing nearly 27 million lbm of proppant across Hanifa formation. The maximum proppant per stage achieved was 606,000 lbm.

The novelty of this project lies in the first-time application of zipper fracturing, as well as the first application of dry HVFR fracturing fluid and dissolvable fracturing plugs in UAE. These introductions helped in improving the overall efficiency of hydraulic fracturing in one of UAE's most challenging unconventional basins in the country, which is quickly demanding quicker well turnovers from fracturing to production.
Interpretation Challenges and Solutions for Real-Time Asphaltene Paramagnetic Sensing at the Wellhead
Authors: Lovell John , Abdallah Dalia Salim , Fonseca Rahul Mark , Grutters Mark , Punnapala Sameer , Kulbrandstad Omar , Meza Daniel , Baez Jorge
Published: December 2021

Asphaltene deposition presents a significant flow assurance to oil production in many parts of the Middle East and beyond. Until recently, there had been no intervention-free approach to monitor deposition in the asphaltene affected wells. This prompted ADNOC to sponsor MicroSilicon to develop of an intervention less real-time sensor device to monitor asphaltene deposition. This new state-of-the-art device is currently installed and automatically collecting data at the wellhead and nearby facilities of an ADNOC operated field.

Historic ways of measuring asphaltene in oil relied upon laboratory processes that extracted the asphaltene using a combination of solvents and gravimetric techniques. Paramagnetic techniques offer a potentially simpler alternative because it is known that the spins per gram of an oil is a constant property of that oil, at least when the oil is at constant temperature and pressure. Taking the device to the field means that any interpretation needs to be made independent of these properties. Additionally, the fluid entering the sensor is multiphase and subject to varying temperature and pressure which raises challenges for the conversion of raw spectroscopic data into asphaltene quantity and particle size. These challenges were addressed with a combination of hardware, software and cloud-based machine learning technologies.

Oil from over two dozen wells has been sampled in real-time and confirmed that the asphaltene percentage does not just vary from well to well but is also a dynamic aspect of production, with some wells having relatively constant levels and others showing consistent variation. One other well was placed on continuous observation and showed a decrease in asphaltene level following a choke change at the surface. Diagnostic data enhanced by machine learning complements the asphaltene measurement and provides a much more complete picture of the flow assurance challenge than had been previously been available.
Automated Intelligent Alarms to Monitoring and Identify Liquid Loading Challenge for Giant Depletion Gas Condensate Fields
Authors: Alsaeedi Ayesha Ahmed Abdulla Salem , Elabrashy Manar Maher Mohamed , Alzeyoudi Mohamed Ali , Albadi Mohamed Mubarak , Soni Sandeep , Raj Apurv , Alkuwaiti Hamda , Sabat Siddharth
Published: December 2021

Depleted well monitoring is a crucial task to ensure continuous production without facing substantial issues that withhold the production, such as liquid loading. Utilizing an integrated digital production system and custom intelligence alarms functionality can help identify and analyze this bottleneck using physics-based model estimations that can help users take preventive actions, leading to saving cost, time, and effort. This paper demonstrates the identification of the liquid loading using custom intelligence alarms and an automated framework.

Initially, a representative compositional well model is added to the digital twin solution enabling the automated well analysis workflow. Subsequently, custom intelligence alarms guidelines are configured to keep the well's performance and production rates under supervision with a notification capability when parameters violate the guidelines.

Along with various well performance parameters being analyzed, two critical parameters for liquid loading debottlenecking, critical unloading velocity and the In-situ velocity, are investigated in the system for each well as the function of depth along well's completion. Moreover, advanced dashboards report the analysis output in an informative manner, guide users’ engineering judgment to take preventive decisions.

As a result of the custom intelligence alarm, gas condensate wells suffering from liquid loading were predicted and identified. Based on the production parameter and target monitoring, these wells were unable to produce their expected mandate resulting in violating the set of production parameters guidelines. Identified wells were run through production gas rate sensitivity analysis using the analytical tool, and in conclusion, the optimal production rate was calculated. Producing the well below this critical rate causes the In-situ velocity to drop below critical unloading velocity. Additionally, using the tuned and calibrated network model, the operating choke was identified to maintain the stable flow in the well and avoid further liquid loading. This choke size was provided to field operation for implementation and saved the cost and man-hour spent during the flowing gradient surveys. The case study demonstrates significant production improvements observed for these wells, thereby significantly reducing cost and time.

Using the integration of the latest production optimization platforms and custom intelligence alarm provides tools to identify wells that are currently experiencing liquid loading challenges and healthy wells that might come under the liquid loading category in the course of production, thus helping in taking proactive remedial action. Furthermore, the integrated framework provides erosional velocity-related data, which acts as a guideline while optimizing gas production.
Virtual Drilling Environments Enable Long Distance Training in Unprecedented Times of Sanitary Emergency
Authors: Ferrara Paolo , Dal Forno Luca , Ricci Maccarini Giorgio , Demetri Katia , Neboli Monica , Tonarelli Francesca
Published: December 2021

During the last five years, a digital training solution, based on Virtual Reality, for immersive and collaborative experience on a virtual drilling rig, was developed and updated by company’s Well Operations Department in collaboration with Corporate University Infrastructures. This paper will present the digital training environment and its applications, including a discussion of all supporting deployment facilities.

The digital Drilling Environment consists in the full digitalization of a last generation offshore semi-submersible drilling rig. On the Virtual Rig, it is possible to access all equipment and workplaces, re-play past operations from a company’s database and interact with a number of safety situations from inductions and drills to the reproduction of a series of real incidental events. The virtual environment is accessible in dedicated 3D rooms, by using Virtual Reality headsets, stand-alone PCs, via lan or by remote internet connections.

The new training method, which proved incremental to traditional approaches, turned out to be decisive in supporting long distance education in unprecedented times of sanitary emergency. In particular, the virtual drilling rig ensures an immersive and collaborative experience of rig operational and emergency conditions, while granting a safe and protected environment where knowledge can be quickly achieved. The necessity to focus on new long distance training approaches and the further enhancement of the virtual drilling environment portability were boosted by the particular world situation, which led to the necessity to address, manage and review the overall company’s educational strategies. This paper is made available to discuss suggestions and to present all lessons learnt.
Vertical Integration Strategy Implementation Through Hybrid Upstream and Downstream Concession Agreements
Authors: Al Jarwan Dr. Abdulla , Sheikh Fathesha
Published: December 2021

Upstream developments in prolific oil and gas fields are highly profitable and hence attract various investors/partners, whereas Downstream developments profitability is margin based and challenging under certain situations to receive similar interest for investment in the same location. Vertical Integration Strategy implementation through hybrid upstream and downstream concession agreements can help address this issue.

The seventies witnessed major changes in the oil industry's structures and strategies resulting from the nationalization of oil and gas reserves. This ultimately led to a separation between the upstream sector with national oil companies (NOCs) controlling most of the world reserves and crude production, and the downstream sector with the international oil companies (IOCs) controlling the largest share of the refining and marketing aspects in the main consuming countries. In the recent past, NOCs have started forward integration of its upstream sector with downstream sector to take advantage of the synergies and increase profitability. This paper takes the strategy a step more forward by exploring the possibility of developing oil and gas assets through a hybrid upstream/downstream concession agreement that can be awarded by the host government.

The model hybrid agreement is built by integrating a typical upstream concession agreement with downstream equity-based joint venture (JV) agreement. It also takes the learnings from Production Development Production Sharing Agreement (DPSA) applied in the development of a Gas-To-Liquids (GTL) asset or Liquefied Natural Gas (LNG) asset which are usually developed as an integrated upstream and downstream business model. It is also feasible to build the hybrid agreement based on upstream Production Sharing Agreement (PSA) instead of a Concession Agreement.

The paper will discuss how the hybrid upstream and downstream concession agreement is built and how it will distribute the risk and rewards across the entire value chain for investors, expand the scope of investment and support in the economic development of the host country.
Research and Application of Micro-Expansion and Anti-Channeling Cement Slurry System in Agadem Oilfield
Authors: Wang Gang , Duan Dexiang , Li Wanjun , Qian Feng , Qin Zhengli , Zhong Zhao , Zhou Chuan , Bahedaer Baletabieke , Jing Ning , Ye Dongqing , Gao Qingyun , Xiao Yue , Li Ganlu , Liu Jitong , Zhang Guobin , Li Shaohua
Published: December 2021

The overall liner cementing qualification rate is only 40% in Agadem block of Niger, The cement slurry system used in the field has a UCA transition time of 43min, and an expansion rate of -0.03% in 24h, which result in a poor anti-gas channeling performance. The expansive agent and the anti-gas channeling toughening agent of anti-channeling agent were optimized through experiment study. A novel micro-expansion anti-gas channel cement slurry system which is suitable for Agadem block was obtained through experiment optimization study: 100% G +2 ∼ 4% fluid loss agent +3 ∼ 4.5% anti-channeling agent +1 ∼ 2% expansion agent-100S +0.15 ∼ 0.4% retarder +0 ∼ 0.3% dispersant +0 ∼ 0.25% defoamer + water. This new cement system has a good anti-gas channeling performance, the cement strength is 24.5-35.0MPa after 24hrs, the UCA transition time is 16-18min, and the expansion rate is 1.5-1.7%. At the same time, a cementing prepad fluid suitable for the block and the micro-expansion cement slurry system is selected to ensure the performance of the cement slurry's anti-channeling performance. The field test results proofs the good performance of the new cement system. The cementing qualification rate of Koulele W-5 well is 96%, and the second interface cementation is Good. The cementing qualification rate of Trakes CN-1 well is 100% which second interface cementation is Excellent. This paper has positive guidance and reference for cementing in Agadem block.
Dynamic Drilling Fluid Invasion Petrophysical Modeling and Corrections in the Presence of Gas Reservoirs - Arab Formation, UAE
Authors: Portilla Cesar , Moreno Javier
Published: December 2021

Drilling fluid (mud) invasion occurs when the liquid component of the fluid (mud filtrate) invades porous and permeable formations caused by the differential pressure between the wellbore and formation fluids. Changes to the fluid distribution near the wellbore region affects logging tool response, especially those with shallow depths of investigation. The Arab formation in UAE exhibits different degrees of invasion primarily observed in the nuclear and resistivity measurements. This study utilizes tool physics, rock properties, logging time information, and drilling fluid properties, to model invasion corrected log responses and estimate accurate petrophysical properties.

Drilling mud filtrate invasion is observed significantly in all wells drilled in the Arab formation in UAE, affecting both wireline and LWD logging tools. Most of the pilot vertical wells appear to be at residual saturations near the wellbore, where drilling mud filtrate invaded deep into the formation and the radial zones near the wellbore are expected to be completely flushed by the filtrate. Drilling mud invasion in the laterals appears to happen early during the drilling phase affecting LWD tool as well, and the measurement becomes function of the time after drilled, affecting mostly nuclear measurements (density and neutron). Clear understanding of the mud filtrate invasion is required to obtain valid petrophysical interpretations.

To characterize these effects, two invasion indexes are estimated and used as inputs for the petrophysical model. Results are then validated with the use of Nuclear Modeling and Resistivity Inversion by the use of the SNUPAR (McKeon et al, 1988)(Edmundson, H., and Raymer, L.L., 1979)(Wiley, R., and Patchett, J.G., 1990) and UTAPWeLS (Jesus and Carlos, 2009) (Alberto and Carlos, 2010) (Alberto, Carlos and Bill, 2010) (Shaaban, David, and Carlos, 2017) (David, Joaquin and Carlos, 2019). Individual models are created to evaluate pilot vertical wells and horizontal laterals, as well as pure theoretical models are put forward to demonstrate the importance of performing corrections for mud filtrate invasion, showing the differences particularly in the nuclear responses.
Application of Wide-Azimuth Anisotropy Inversion Predicting Carbonate Fracture Intensity and Direction
Authors: Guo Tongcui , Wang Guihai , Song Xinmin , He Dongbo , Zhang Jian , Liu Weiliang , Deng Xili
Published: December 2021

Fractures in carbonate rock are both storing reservoirs and migrating channels for oil and gas, so such fractures are one of the key targets for oil exploration and development. Traditional fracture prediction methods by seismic data include ant tracking cube, coherence cube and other seismic attributes. Fractures predicted by these methods are less accurate. This paper introduces a wide-azimuth anisotropic inversion method to effectively predict the fracture density and direction in carbonates. a wide-azimuth seismic anisotropy inversion workflow is established to predict the fractures in carbonates, and consequently the fractured zones in the target layer. The key steps include: (1) carry out quality control and optimization of wide-azimuth seismic gathers; (2) conduct pre-stack simultaneous inversion of pre-stack seismic data at partial sub-offsets and sub-azimuths to obtain the Vp/Vs of the azimuths; (3) use Azimuthal Fourier Coefficient to calculate the anisotropic gradient and direction. Based on the anisotropic intensity and direction and elastic parameters in the study area, the density and direction of fractures are obtained. The prediction results show that in the study area, nearly SN-striking fractures are developed, which are chiefly tectonic fractures, and consistent with the imaging logging results. It has been proved that the method is reasonable and feasible, and the accuracy of fracture prediction is improved.
A Robust Predictive Machine Learning Model for Supercritical CO2 Foam Strength with Integrated Testing Parameters
Authors: Ahmed Shehzad , Alameri Waleed , Ahmed Waqas Waseem , Hanamertani Alvinda Sri , Khan Sameer Ahmed
Published: December 2021

Unconventional resources have made a significant contribution to fossil energy supply to date, and some specific stimulation techniques have been used in their exploitation. For example, the use of scCO2 foam as a hydraulic fracturing stimulation fluid has sparked considerable interest due to its numerous advantages in terms of fracturing and production performance. The strength of scCO2 foam, an indicator of foam performance, highly depends on the formulation design, foaming properties and operating conditions. Due to complex nature of foam, the quantification of foam strength at downhole conditions is challenging. Specific screening and optimization processes are required to design high performance foam. Although the flow behavior (apparent viscosity) of foam has been extensively studied with empirical models, integrating some essential process parameters into the foam flow behavior evaluation remains challenging. In this study, we present an effective model that incorporates the benefits of a deep learning (DL) approach while taking into account the integration of specific process variables. Several input parameters such as surfactant types and concentration, salinity, polymer concentration, temperature and pressure were used in conjunction with foam quality and shear rate. To predict foam strength while taking the aforementioned parameters into account, a deep neural network (DNN) with optimized hyperparameters was developed. The experimental data for this purpose were obtained using a pressurized foam rheometer. An improved deep learning framework was developed and designed to learn the intrinsic relation among various parameters. The predictive study concludes that, the developed optimized DNN algorithm can provide a reliable and robust prediction with significantly high accuracy. When compared to a shallow network with a standard deviation of less than 5%, the developed optimal deep neural network increased average predictive accuracy to 95.64%. The regression coefficient in the optimized case was found to be nearly one with a low mean square error. The developed DNN algorithm is considered as an improved framework which encompasses several process variables and provides reliable and accurate prediction thus makes it suitable for further integration with fracturing simulator. It would also be helpful for optimizing fracturing process and improving foam formulations.
Improved EOR Polymer Selection Using Field-Flow Fractionation
Authors: Steindl Johannes , Hincapie Rafael Eduardo , Borovina Ante , Puls Christoph , Badstöber Johann , Heinzmann Gerhard , Clemens Torsten
Published: December 2021

Various polyacrylamide polymers have been successfully applied in chemical EOR projects. These polymers are characterised by high molecular weights (MW) to achieve high viscosifying power. The molecular weight distribution (MWD) of the polymers has a major impact on polymer properties and performance. Measuring the molecular weight distribution is challenging using conventional methods. Field-Flow Fractionation (FFF) enables the determination of the distribution to select and quality check various polymers. Polymers with high molar masses (> 1 MDa) are used for EOR to obtain highly viscous aqueous solutions. The MWD of the polymers is crucial for the solution characteristics. Conventional analysis of polymers is performed using either viscometry – which is able to determine the average MW but does not give information on MWD, or size-exclusion chromatography – which is restricted to molecular weights of < 20 MDa. FFF is based on the analytes flowing at different speeds in a channel dependent on their size and mass. This effect leads to separation, which is then used to determine the MWD.

FFF allows to determine the MW and MWD of various ultra-high molecular weight polyacrylamides (HPAAMs). The FFF measurements showed, that despite similar MWs are claimed, substantial differences in MWD are observed. This technology offered the quantification the MWD of HPAAMs up to a MW of 5 GDa. Furthermore, gyration radii of the HPAAM molecules were determined. Selecting polymers on viscosifying power only is not addressing issues related to different MW and MWDs such as selective polymer retention and degradation of the high molar mass part of the distribution. The results were used to improve the polymer selection for chemical EOR projects.

Overall, this work presents a new technique for analysis of ultra-high molecular weight EOR polymers, which enables the possibility to determine the full range of polymer MWD. This available information enhances the EOR polymer selection process addressing selective polymer retention and mechanical degradation in addition to the viscosifying power of polymers.
Realtime Wellbore Digitalization for Stimulations Using Multi-Well Fiber Optics
Authors: Li Xinyang , Chavarria Andres J. , Oukaci Yassine
Published: December 2021

Distributed Fiber-optic Sensing (DFOS) provides real-time data acquisition, monitoring and diagnostics for well stimulation and well spacing assessment. These include measurements of Distributed Acoustic Sensing (DAS) with high frequency acoustics in treatment wells, and low frequency strain/temperature sensing in offset monitor ones. The goal of this integrated study is to show the value of multi-well fiber sensing for real time fracturing diagnostics and stimulation optimization. By integrating near field injection to far field strain responses we assess overall reservoir development.

The availability of fibers on both the treatment well and a nearby observation well allows us to investigate the near-wellbore injection profile and the far-field strain fracture propagation. Quantitative strain levels clearly respond to the effects of well distance, location and treatment well stimulation design. Monitoring well strain measurements of fracture density and triggered stimulated span were logged and compared to acoustic signals in the nearfield stage by stage. DAS interpretation was conducted during the treatment of each stage indicating the effectiveness and efficiency of the completion design. Results show that this is a very effective tool to better understand the performance of the fracturing treatment by digital transformation using DAS data. In addition, acoustic and strain measurements also validated its diagnostic capability for real-time operation monitoring.

In this presentation we show how the near-field acoustic and far-field strain measurements allow for better understanding of the completion efficiency. This is by assessing the far field response to quantified DAS injected signals in the treatment. This analysis takes advantage of fiber installation on both the treatment and nearby monitor well. The fluid and proppant allocations in the near field were performed on the treatment well using relative acoustic intensities. Meanwhile, the fracture propagation induced strain change is recorded by the offset fiber well. Using this fiber data reveals dominant clusters and stage bias from near-field injection profile. Simultaneously the far-field identified fracture counts from strain further enable a geomechanical assessment of the stimulated reservoir and assess the effectiveness of the completion design.

Multiple DAS fiber equipped wells not only provide single diagnostic tool for each of the fiber well, but also demonstrate significant integrated assessment of the stimulation effectiveness, completion efficiency, well interaction, and reservoir description. Availability of near and far field measurements constitutes an important tool to assess properties of the reservoir. Here we show how different vantage points can help illuminate a fracturing program in unconventional reservoirs.
Accelerating Hydrocarbon Maturation and Project Delivery by 30% with Digitalization - Standardizing on the Fly Analysis to Enable Informed Decision Making Using Petabytes of Petro Technical Data
Authors: Gupta Himanshu , Farmer Beth , Large Samantha , Balushi Majda , Saadi Laila , Kumar Kamlesh , Moreno Carlos Alberto , Ruqaishi Mohammed , Busaidi Yusra , Hillgartner Heiko , Agarwal Binayak , Abri Said
Published: December 2021

In recent years, with the steep drop and increased volatility in oil price, there is an urgency for making our field (re-development) plans more dynamic and efficient with faster payback and with particular emphasis on robustness against uncertainties. This paper describes a root cause analysis and a methodology to achieve up to ~30% improvement in field development planning project cycle and developing a better-integrated reservoir understanding.

A comprehensive integrated analysis of available data is a key success criterion for robust decision-making. A detailed value stream mapping and a timeline analysis for data analysis in the hydrocarbon maturation process revealed that our process cycle efficiency is only 16% with a significant room for improvement. Any improvement can be directly translated to man-hour cost saving and acceleration of oil delivery. Effective use of technology and digitalization for knowledge management, standardized ways of working and easy access to historical data, analysis and diagnostics were identified as key focus areas to improve delivery.

An innovative process and web based digital platform, iResDAT, is developed for accelerating data analysis. It mines from volumes of petro-technical databases and translates data into standardized diagnostics using latest data analytics and visualization technologies. It has already reduced dramatically the time to mine critical subsurface data and prepare required integrated diagnostics that are auditable and can be re-created in a few seconds. Based on the early pilot studies the cycle time reduction in the data analysis phase is close to 30% with improved quality and standardization of the integrated analysis.

It has already transformed the ways of working where the subsurface discussion can happen across disciplines using a single platform that enforces early integration for reservoir understanding and associated uncertainty characterization. It is a web-based platform where the diagnostic dashboards are crowd sourced; sustained and enhanced by the business to ensure the relevance and sustainability with the Corporate Data Management and IT functions. It is a building block towards quality controlled and auditable data analysis and interpreted dataset, which may form the backbone for any advanced analytics in future to enable digitally enabled hydrocarbon maturation.
Next Generation Torsional Vibration Isolation Tool Increases BHA Reliability Proven by Field Operations in North Sea
Authors: Kueck Armin , Kulke Vincent , Schepelmann Cord , Peters Volker , Ostermeyer Georg-Peter , Reckmann Hanno
Published: December 2021

High Frequency Torsional Oscillations (HFTO) generate high torsional loads in the BHA causing cracks, damaged electronics or twist-offs. A new Torsional Vibration Isolator tool (TVI) protects the BHA by restricting vibrations to the tools between bit and TVI. Additional features have been added to the tool to automatically indicate torque overloading of the BHA and to increase torque resistance if required. This paper proves the functionality of the new features analytically, on a small-scale laboratory test and in multiple field deployments in the North Sea. New guidelines for field operations are provided.

The new feature is a torsion limiter which automatically engages on reaching a critical torque threshold. The torque is then re-routed through more torque resistant BHA components. The engagement generates a characteristic signal indicating bit or BHA-overloading. The mechanical design of the new feature is presented. A criterion for engagement of the limiter and the signature indicating critical torque are analytically derived. They are experimentally validated on a scaled version of the TVI in a laboratory test. A prototype of the new tool is manufactured and deployed in multiple field operations in the North Sea previously heavily affected by HFTO. Two high-frequency measuring devices identify critical drilling situations on a scale of Milliseconds. A new guideline for utilization of this tool is developed including recommendations for BHA set-up and operational parameters.

The TVI works as intended and protects the upper BHA from torsional loads generated by HFTO. The new feature engages at the predicted contact parameters. The signature indicating critical torque for the BHA was recorded and corresponds to the signature measured in the lab and predicted by the model. The TVI is best placed as close to the bit as possible, and a high-frequency measuring device in the BHA is recommended to record and transmit the contact indicators to surface. Based on field tests a parameter map for drilling torque and RPM is created that displays zones of safe operational parameters in a plain manner for field engineers. The map was validated in the field, and harmful drilling states were prevented by following the recommended drilling parameters.

The next generation TVI protects BHAs from damage due to torsional vibrations. The new feature enables operations in stuck-pipe situations by increasing the torque when required. The overloading indicator prevents overstepping the torque limit of the bit and the BHA. The new parameter map and best-practice recommendations transport the learnings to the field in an easy-to-use manner.
Latest Trends in Pig Detection System
Authors: Mondal Jagannath , Umakanth Devarajan , Paul Raju , Kamal Faris Ragheb
Published: December 2021

Pig detector plays an important role in the Commissioning and handover of Pipelines project. This paper addresses the latest trends in Pig Detectors. In addition, this paper covers the commissioning challenges and mitigations in major Offshore Brownfield Project involving new pipelines with 80 nos of Pig Detectors and accessories.

Pipelines represent a considerable investment on behalf of the End User and can often prove strategic to countries and governments. Pipelines are generally accepted as being the most efficient method of transporting fluids across distances. Pipelines transport various kinds of fluids viz. oil, gas, multiphase, water. Pipeline pigging is an important operation for enhancing reliability and durability of pipeline, adopted worldwide. It has a major impact on the operational and technical integrity of a pipeline. Pigging Operation is high-risk activity in-terms of process safety. The Pigging can be safely initiated only when safe operating conditions are maintained at both ends of pipeline. Pigging involves human intervention and thus increasing personnel risk. Pipeline pigging operations is performed during pre-commissioning, start-up, normal operations and integrity assurance.