bluuebunny/crossref_metadata_2025 huggingface dataset:
Multi stage Frac & Testing of High Angle HPHT Ultra Sour Exploratory Well: Challenges Encountered & Mitigated
Authors: Al-Dosari Saad Abdullah , Al-Ateeq Abdullah Fahad , Ranjan Akash , Salem Abrar , Asthana Saurabh , Peiwu Liu
Published: March 2023

Reservoir production challenges are always escalated when the concentration of H2S and CO2 are extremely high. This paper highlights the challenges encountered, mitigation techniques used to overcome hurdles, and remaining tasks in testing the first deep high angle High Pressure High Temperature (HPHT) exploratory well completed with Multi-Stage Completion (MSC) in the presence of ultra-sour fluid (H2S-31% and CO2-38%) in Kuwait.

The subject Jurassic well is drilled at a highly deviated angle up to 19,000 ft in measured depth (MD). The completion installed is composed of an open-hole MSC and three stages of frac ports tied back with a Liner Hanger to the upper 4.5 inch tubing. After setting the completion, the 15.8 ppg oil base mud (OBM) completion fluid was displaced with 11.6 ppg brine. DataFrac treatment and analyses were followed by acid fracturing treatment in all three stages. Post-fracturing well clean-up is achieved by continuously pumping Hydrogen Sulfide (H2S) scavenger to protect the entire surface test equipment set up. Employing self-containing breathing apparatus for personnel safety and having two flare pits permitted uninterrupted well testing for 13 days.

During the well clean-up, the very high H2S and Carbon Dioxide (CO2)concentrations in knocked out fluid were 31% and 38%, respectively. However, due to the extremely high sour nature of reservoir fluid and limitation of separator metallurgy, the flow rate measurement is limited to only 2 hours. Various technical and operational safety challenges were safely handled during the well preparation, acid fracturing, testing, and flaring operation without any HSE incident. Moreover, continuous flow rate measurements are not achieved due to equipment limitations. Currently, a multi-phase flow meter (MPFM) which can handle high H2S and CO2 is under evaluation to conduct long term well testing to ascertain the production potential.

The completion of three stage acid fracturing treatments and safely testing the high sour deviated well in HPHT conditions of an exploration well for the first time in the State of Kuwait is a remarkable success, paving the way for future field development in similar well conditions. However, production and processing of this highly sour fluid will be challenging for field development.
Detailed Core Studies and Facies Characterization of Tight Cambro-Ordovician and Devonian Reservoirs (Tinrhert Nord Block, Illizi Basin, Algeria).
Authors: Guney Hasan , Ellen Helby , Ajayi Ayodeji Temitope , AlAli Abdulla Ali , Bezziane Mohamed Lamine
Published: March 2023

The Tinrhert Nord Block is located in the Illizi/Berkine-Ghadames Basin where in the central-eastern part of Algeria, near the border with Libya. The sedimentary infill of these basins is composed of thick Palaeozoic sedimentary sequences which constitute a world-class petroleum system, confirmed and producing in Algeria, Tunisia and Libya. Previously drilled wells by Sonatrach in the block had shown a considerable prospectivity for the Block, and further studies were undertaken for well planning and appraisal of the Ordovician, Silurian, and Devonian reservoirs. The target of this study was to better understand the characteristics of the reservoir and quality of the productive series in the block. A comprehensive core study was therefore run for 15 wells with a total of 647 meters of sediments in the Tinrhert Nord block (Figure 3). The study showed that 7 clastic facies for the Palaeozoic sequences can be distinguished. The Ordovician facies subdivided into 3 main facies that were deposited in Glaciomarine, Tidal-Delta and Upper shoreface-shoreline environment and is composed of diamictites, titillates and fine-grained tight reservoir facies. Silurian and Devonian sequences are composed of marine shales that are confirmed as constituting the major source rock in the basin (Silurian hot shale and Frasnian hot shales), and additional fluvial-deltaic coarse-medium-fine grained sandstone facies. SEM (Scanning Electron Microscope), routine core analysis, and fracture studies were performed on selected core intervals in order to perform a more detailed reservoir characterisation. Routine core analysis show that the Ordovician reservoir has a limited porosity up to 4-8% due to the overall texture of the sediments and shows also a low permeability (<1Md). Effective porosity of the Upper Silurian F6 reservoir is up to 15-20% and Devonian F2 reservoir is most likely up to 10%. Core fractures show drilling-induced vertical fractures, and natural hairline type healed fractures, and an additional natural open joint system. The open hole DST well tests that have shown moderate flow rates with can be related to the presence of a high porosity and main permeability system which is composed of interconnected small scale open fractures and larger scale sub-seismic fracture corridors. These features permit to produce also from the reservoir layers that generally show low porosity/permeability facies.

These studies confirm that the Silurian F6 reservoirs are the best reservoirs in the basin and Devonian fluvial-deltaic sequences (C and F2)are secondary best reservoir in the basin. The Ordovician reservoirs are tighter with limited porosity and permeability but can be produced by stimulation of the natural fracture system.
Numerical Simulation of CO2 Mineral Trapping Potential of Carbonate Rocks
Authors: Mouallem Johny , Arif Muhammad , Mahmoud Mohamed
Published: March 2023

During CO2 geo-storage, mineral dissolution is considered as the safest trapping technique however it is the longest and the most complicated trapping mechanism involving geo-chemical reactions and physical forces like diffusion and advection. Many factors also influence the mineral trapping capacity of the geological formation e.g., mineralogy, temperature, pH, CO2 fugacity, pressure of CO2, salinity and impurities.

The scope of this study is to investigate the mineral trapping of CO2 in Arabian carbonates reservoirs as a function of CO2 pressure injection, presence of contaminants and well configuration. Numerical simulations were performed using the multi-phase simulator GEM-CMG. 2D and 3D models were developed to examine the mechanisms occurring during mineral trapping and how these affect its efficiency. The mineralogy of a carbonate field from an Arabian formation was used. Sensitivity analysis was performed on the above variables on CO2 mineralization tendency.

The results suggest that dissolution and precipitation of minerals occurred during and post CO2 injection. Increasing pressure led to higher amount of CO2 trapped while the presence of impurities in the injected fluid reduced the potential of CO2 mineralization. Moreover, using horizontal well tends to promote the mineral activity during CO2 storage.

While a score of publications investigated CO2 storage via structural, residual and dissolution trapping mechanisms, still the mineral trapping potential and its influencing factors have not been investigated much. This paper thus provides insights into CO2 sequestration by mineral trapping pertinent to Arabian carbonate rocks.
Negatively Charged Polyelectrolyte-Complex Nanoparticles Using Pei/pvs for Encapsulation of Fracturing Fluid Breakers
Authors: Alhajeri Mubarak Muhammad
Published: March 2023

Hydraulic fracturing treatment is a stimulation technique in low-permeability reservoirs and tight rock formations. It involves pumping large quantities of fluids into the well at extremely high pressure. Due to hydraulics, it creates small cracks in the rock formations called fractures, allowing reservoir fluids such as natural gas, petroleum and brine to flow out of tight formations. Nanotechnology leads the research direction especially in the field of hydraulic fracturing. This paper/poster presents a novel approach for improving the fracture cleanup process, using negatively charged assembled polyelectrolyte-complex (PEC) nanoparticles as a technique for targeted and controlled release of enzyme breakers. Our previous work (Alhajeri et al. 2021) showed that positively charged PEC nanoparticles using the Polyethylenimine-Dextran Sulfate system can produce stable nanocontainers for enzyme breakers during the hydraulic fracturing process. However, negatively charged PEI/DS nanoparticles showed a significant loss of fracture clean-up efficiency due to the high pH level over the encapsulated enzyme that led to denaturing. In this study, negatively charged PEC nanoparticles were formed by the mixture of polyethyleneimine (PEI) and poly(vinlySufonic acid) (PVS) in nonstoichiometric amounts to encapsulate breakers. It is hypothesized that PEI/PVS system would provide a higher controlled release of breaking agents with high loading capacity due to lower toxicity levels. The development of negatively charged PECs nanoparticles was examined. The nanoparticles were assembled by means of alternate electrostatic adsorption of a polyanion (PVS) and a polycation (PEI). Enzyme-breaking agents were introduced into the PECs during the complexation process. A screening test of the PEI/PVS PEC loaded with enzyme was conducted based on particle size, polydispersity, and zeta potentials. The most stable PEC structure was selected for Enzyme viscometric assays to measure the entrapment efficiency (EE,%). Results from this study demonstrated a proof of concept that negatively charged PEC nanoparticles using PEI/PVS can be used to encapsulate fracturing fluid breaks, minimize premature degradation of fracturing fluids, and provide protection from inhibited surroundings at downhole conditions. In addition, the negatively charged PEC nanoparticles show higher particle stability in terms of smaller particle sizes (>200 nm) and zeta potential (> - 40 mV) for more than 94 hours, thus; improving fracturing clean-up efficiency. The general goal of this study is to develop nano-sized particles loaded with enzyme breakers capable of functioning within fracturing fluids during fluid leak-off into the reservoir matrix, filter cake development, and hydraulic fractured area.
Organizational Safety Culture Transformation Through Coaching
Authors: Okeudo Ameze , Odiase Kevin
Published: March 2023

Organizational culture is simply known as ‘the way we do things around here’. Culture is developed over the time and evolves as people transit through the organization. It is an uphill task to transform organizational culture when this is not desirable, with regards to safety, it becomes even more important that the right mindset and behaviours are modelled across the organizational strata as these are fundamental to keeping people, asset and the environment safe. When focus is placed on keeping safety track records, personnel become wary of reporting incidents for fear of toppling the safety performance. Another factor that contributes to under reporting is the attitude of the leaders when receiving ‘bad news’ of an incident, excessive questioning, blame culture and consequence management for failures creates an environment of fear and inability to intervene in unsafe conditions.
Experimental Study on the Effects if Ift Reduction on Water Blockage after Hydraulic Fracturing in Tight Sandstone Reservoirs Based on The NMR Method
Authors: Hou Xiaoyu , Sheng James J. , Dai Jiacheng
Published: March 2023

The current studies regarding the effect of interfacial tension (IFT) reduction on removing the water blockage of tight sandstones are significant, but the migration characteristics of trapped water in the stimulation process have not been researched. These issues lead to the stimulation mechanism of IFT reduction after hydraulic fracturing is unclear. In this work, a new coreflood platform was designed to simulate the water invasion, shut-in, and flowback process, and how the IFT affects the water blockage was further studied from pore levels. The oil production rates before and after shut-in were measured, which were used to detect the regained permeability of tight sandstones. The T2 spectrum signals, 1D frequency, and magnetic resonance imaging (MRI) based on the nuclear magnetic resonance (NMR) experiments were used to explore the migration characteristics of trapped water under different conditions. The results indicate that the core damage induced by water invasion is severe. The regained permeability is decreased to less than 25% after shut-in. IFT reduction is an effective way to improve the regained permeability, but the emulsification effect of fracturing fluid needs to be avoided, which will reduce the permeability of tight sandstones by the Jiamin effect. The NMR signals of the 1D profile show the water saturation of cores gradually decreases from the fracture face to the exit end, which demonstrates that the water blockage occurs mainly in the area near the fracture face. The T2 spectrum signals show that the residual water saturation of mesopores and macropores after flowback can be reduced by decreasing the IFT values, but the reduction of residual water saturation in micropores is insignificant. This result demonstrates that the core damage caused by water blockage may mainly come from mesopores and micropores. Our study reveals a deeper mechanism of removing water blockage during the IFT reduction process, which can guide the application of surfactants in the oil field.
Reduced Polymer Loaded Fracturing Fluid For Extreme Temperature Proppant Fracturing
Authors: Karadkar Prasad , Malik Ataur , Alabdrabalnabi Mohammed , Liang Feng
Published: March 2023

Guar gum and its derivatives based fracturing fluids are most commonly used in hydraulic fracturing. For high temperature wells, guar-based fracturing fluids need to be formulated with higher polymer loading and at high pH that leaves insoluble residue and tendency to form scales with divalent ions. In this paper, newly developed reduced polymer loaded fracturing fluids based acrylamide polymer was deployed from lab developments to field implementation. A thermally stable acrylamide-based polymer with a reduced polymer loading of 30-40% less than guar-based fracturing fluid was considered to minimize formation damage concerns. The crosslinked fracturing fluid viscosity was optimized at 340°F, bottomhole static temperature, and 315, 290, 265 and 240°F cooldown temperatures using a high pressure high temperature (HPHT) rheometer. For successful field deployment, a novel reduced polymer fracturing fluid was evaluated in the following sequence: chemical management, quality control, optimization of fracturing fluid formulations with field water, field mixing procedure, on-site QA/QC, data frac analysis and execution of main treatment.

This paper presents rheological studies of reduced polymer loaded fracturing fluids at bottom hole static temperature (BHST) and cool down temperatures of selected well candidates that demonstrate the superior thermal stability of this novel fracturing fluid. With a polymer loading of 35 lb/1000 gal, the fluid viscosity stayed above 300 cP at 100 1/s shear rate for 60 min at 340°F. The fracturing fluid formulations were optimized using both live and encapsulated breakers using high pressure and high temperature rheometer. Due to the fast hydration of the base polymer, the linear gel was mixed on-the-flying during the main fracturing treatment. The main fracturing treatment was successfully executed with a 40 barrels per minute (bbl/min) pumping rate with increased proppant concentration up to 4.5 pounds per gallon (ppa) using 40/70 HSP (high strength proppant) proppant. The fracturing fluid system based on the novel acrylamide copolymer offers advantages over guar-based fracturing fluid such as low polymer loading, excellent high temperature stability and less formation damage. This paper presents a systematic approach and lessons learnt during novel fracturing fluid deployment.
Novel Techniques to Prevent Wax Deposition During Hydraulic Fracturing of Low-Temperature Waxy Oil Reservoirs
Authors: Dadwani Aashish Dheeraj , Shah Maunish Sanjay
Published: March 2023

Hydraulic fracturing is the key well-stimulation technique to recover oil and gas from tight and unconventional reservoirs. The primary challenge encountered during hydraulic fracturing of the shallow waxy oil reservoir is cooling the reservoir while pumping low-temperature fracturing fluid, resulting in wax precipitation. Heating the fracturing fluid at the surface and blending water-dispersed paraffin inhibitor with fracturing fluid are the two techniques that prevent wax precipitation when the reservoir temperature decreases below the wax appearance temperature. This paper will suggest the best suitable technique for given reservoir conditions. When the formation temperature is cooled below the cloud point temperature, the paraffin precipitates and deposits in the reservoir pores causing formation damage. It is therefore suggested to maintain wellhead temperature above the wax appearance temperature of crude oil in the reservoir.

An adequate concentration of viscosities would be selected to maintain desired viscosity at field conditions by identifying the suitable rheological model for propane placement in the reservoir. This would also suggest modification in infrastructure and formulation of cross-linked gel for the treatment. The paper would discuss the challenges faced when this method is upscaled at the field scale. This paper would also investigate a novel approach by incorporating insoluble paraffin inhibitors into a micro-dispersion system dispersible in water. Hydrofracturing fluid follows Herschel Buckley’s rheological model, which is a modification of the power law model. On increasing guar gum concentration by 1.5 gm/liter (50 lb/1000gal to 62 lb/1000gal), the average change in apparent viscosity is observed to be 14-20 cP depending on temperature. If we need to heat the fracturing fluid at 70°C, the concentration of guar gum needs to be increased. At 34°C, the apparent viscosity of standard hydro-fracturing is observed to be around 41 cP and at 68°C, viscosity decreases to 28 cP. After increasing the guar gum concentration by quantity 1.5 gm/liter, we observe that viscosity at 68°C becomes around 44 cP. The optimum concentration of guar gum needed to maintain viscosity is around 7 gm/liter (58.4 lbm/1000 gal). Hence it should be increased by about 16.67%.

From the study of wax appearance temperature at the laboratory scale, the impact of water-dispersible paraffin inhibitors on paraffin control, oil quality, water quality, fracturing fluid compatibility, and production rates are evaluated. It is observed that production rates decline even after the hydraulic fracturing of the well, as paraffin damage reduces the formation's permeability. Thus, heated fracturing fluid and micro-dispersed colloidal paraffin inhibitors are the visionary methods to inhibit wax formation at the reservoir scale. It can be salubrious for the operators in stimulating +the reservoirs.
Productivity and Cost Comparison Between Radial-Borehole Fracturing and Horizontal Well Fracturing in Shale Oil Reservoir
Authors: Dai Jiacheng , Zheng Zeyu , Wang Tianyu , Li Gensheng
Published: March 2023

Given the abundant reserves, shale oil resource has great potential for future utilization. However, shale formation is often characterized by complex geological structures and developed stratification, which greatly restricts the formation stimulation performance of volumetric fracturing along the vertical direction in horizontal well and therefore raises development costs. To address such issues, a new method that utilizes radial-borehole fracturing based on vertical well is proposed to extract shale oil. This paper describes the fracturing network under radial borehole fracturing. A numerical model that considers shale formation, hydraulic fractures, and the wellbore is built to predict the productivity of radial-borehole fracturing and horizontal well fracturing. Moreover, a simplified cost evaluation model is built, respectively.

Furthermore, this paper analyzes the influence of different well patterns, fracture heights, and Kv/Kh ratios on radial-borehole well productivity and compares the cost-effectiveness of a radial-borehole fractured well and horizontal well fracturing. Results indicate that radial-borehole fracturing is capable of eliminating the constraints of fracture height and thereby improving stimulation performance; more radial boreholes and main wells result in more oil production; in addition, as the fracture height decreases, the ratio Kv/Kh is closer to 0, it is more recommended to use radial borehole fracturing. A case study of Eagleford shale oil reservoir is herein carried out: The 9-vertical well, 3-layer, 4-lateral radial borehole fracturing brings the same oil production as the 3-horizontal well multistage fracturing (open hole completed) does, while the former costs 0.36 M$ less of the latter. Using radial borehole fracturing method to develop shale oil is proposed in this paper. The results can provide new insight into the effective development of shale oil resources at low cost.
Experimental Investigation of Asphaltene Deposition Remediation in Northern Iraqi Fields Using Green Metal Oxide Nanofluids/chemicals as Dispersants
Authors: Khidhir Dana Mohammad , Sidiq Hiwa
Published: March 2023

Precipitation of asphaltene is a significant technological Hurdle for the petroleum industry. There are several processes utilized to eliminate or stop the precipitation of asphaltene, while the applications of asphaltene inhibitors give the most efficient and cost-effective method of treating deposits. This study examined the practical effects of Asphaltenes were studied using inhibitors (ASFIN and ZnO NFs) also the remediation of asphaltene in dynamic conditions in terms of Pressure, Temperature and inhibitor concentration. An asphaltene precipitation loop was designed to mimic the real production scenarios in field conditions. It was found that nanofluids outperformed typical chemicals used in asphaltene remediation by a significant margin. Results of this experiment were then tested by UV-vis spectrophotometer which showed significant adsorption of asphaltene by nano particles.
Foam Formulation Development and Pilot Application in Low-Permeability Reservoirs
Authors: Zou Xinyuan , Luo Wenli , Wang Zhengbo , Jiang Zhibin , Han Xu , Chang Zhidong
Published: March 2023

Foam flooding has been widely studied and implemented in recent years to alleviate reservoir heterogeneity and increase oil recovery. Previously, foam flooding was employed for conformance control and improving sweep efficiency, and little attention was paid to displacement efficiency. Thus, foam flooding usually had a poor ability to trip off oil film. Moreover, the effectiveness of many of the foam pilots lasted only a few months, and, in some cases, only a few weeks, which limited the long-term development of foam in field applications as the time to maximize effectiveness was too short. In this paper, a foam pilot selection, formulation design, and N2 foam pilot implementation are presented towards providing an effective method for transforming the development mode after water flooding in low-permeability reservoirs.

Two well groups (two injection wells and 17 production wells) were screened as candidates for the N2 foam pilot. Laboratory investigations included bulk foam screening, imbibition recovery, and natural core flooding tests. One formulation of eight tested (No. 6) showed excellent foam properties as well as a strong ability to strip oil from sand, and natural core scale work under reservoir conditions resulted in a total recovery of 66.92%, with an incremental recovery of 25.25% by N2 foam after water flooding.

The pilot was deployed using a new injection strategy of a surfactant alternating gas method in which surfactant was injected into water for 1 d at a normal injection rate followed by N2 injection for 1 d at a large injection rate. A positive response was observed after injection for approximately 1.5 months, daily oil production climbed sharply, and water cut also decreased after processing of 1% of pore volume with foam solution. Moreover, production was sustained for 18 months after foam injection, which resulted in approximately 4375 t of incremental oil. The foam pilot was successful in addressing the challenges associated with dominant channel and low displacement efficiency of water flooding in low permeability sand reservoirs.
Uplifting Engineer's Competency for Unlocking Asset Value in The Energy Transition Era: Cross-Organizational Knowledge Sharing Management System
Authors: Yonebayashi Hideharu , Matsubuchi Hitoshi , Shoukry Medhat , Al Marzouqi Adel Abdul Rahman , Abdesalam Elmansouri Mohamed Elhassan , Al Remeithi Hamda Mohamed , Eshbair Ibrahim , Kawahara Hiroshi
Published: March 2023

E&P technology in the energy transition era is more rapidly progressed because of various innovations from other industries, digital transformation, and broader knowledge sharing from other industrial sectors. Therefore, skills of engineers in frontline: namely employees in operating companies (OPCO) will have deeper impacts on project values. To uplift their technical competency, this paper discussed how to maximize leaning/training program values and provide the opportunities from long term perspective as a part of holistic talent development management system. In-house leaning/training courses and/or commercial training programs, which have been commonly provided, will not be sufficient for pursuing competitive level in future as long as the knowledge sharing opportunities are limited to in-house or generalized contents for maximum numbers of demand. Thus, the opportunities are unlimited by incorporating additional seminar/training courses, offered from stakeholders: an asset lead in particular, into the OPCO's youth development plan (YDP) to be more effectively provided from many viewpoints of participant adequateness (discipline, technical interest, maximum number of attendees), annual schedule planning, and interactive feedback to improve the programs.

INPEX/JODCO, an asset lead international oil company (IOC) responsibly developing concession of the Abu Dhabi offshore field, has been operating domestic oil/gas fields and an abroad giant LNG project, furthermore, managing various non-operating projects all over the world. From all the projects, therefore, many types of knowledge-sharing seeds have been gathered to prepare seminar/training contents and lecturers via the IOC's corporate technical division while taking OPCO's demands into account. Dozens of programs have been offered since 2018 for various disciplines. One of them: the JODCO Drilling Academy (JDA), providing total 61 courses as of November 2022 covering major drilling & completion related topics is recognized as the most successful contribution. A cycle from seminar planning, execution, feedbacks, and updating are established to work as a cross-collaborative talent development management system.
Deliberate Selection of Wellbore Flow Profiling Technology
Authors: Tveritnev Alexey , Boyd Douglas Alexander , Abdel Aziz Ahmed
Published: March 2023

Wellbore production / injection flow profiling provides key information for reservoir production and hydrocarbon recovery management. To collect wellbore liquid / gas flow profile data, ADNOC's Onshore Engineers utilise three proven technologies; Production Logging Tools (PLT), Fiber Optical Downhole Temperature Sensors (DTS) and Inflow Chemical Tracers (ICT) placed on the completion. Each technology utilises different physics and has unique implementation requirements. The optimum monitoring technology is selected at the well planning stage with considerations to well design, completion type, fluid type, well purpose (injector or producer), economics, technology reliability, installation / data collection operational considerations, expected lifetime, interpretation confidence, field maturity and field monitoring strategy. Each monitoring option might be applicable under certain operational and well construction constraints, and provide results within required uncertainties. This paper shares ADNOC Onshore's guidelines for the selection of the most appropriate flow monitoring technology for its oil and gas reservoirs developed primarily with horizontal wells and water injection for pressure support.
Intelligent Wireline Formation Tester Evaluation of Low-Permeability and Low-Resistivity-Contrast Formation with Detailed Digital Planning.
Authors: Guan Lijun , Wang Xiannan , Wang Jian , Bei Gao , Gisolf Adriaan , Fan Zhaoya , Partouche Ashers , Kristensen Morten , Li Shiju , Chen Li , Chen Jichao
Published: March 2023

Exploration and development drilling in offshore China is extending to Paleogene formations that are characterized by low-resistivity-contrast and low-permeability rocks. These formations have become a focus for increasing reserves and production. During exploration activities, these low-resistivity, low-formation-contrast formations have been critical and challenging for formation evaluation because the geological structure and lithology are more complex than in previously discovered fields. Differentiating hydrocarbon from water using petrophysical interpretation has a large uncertainty in these formations. Confirming the fluid type using conventional formation testing technology has been extremely challenging because the produced fluid is mainly mud filtrate, which is of no use for fluid confirmation.

The dual-flowline architecture of the intelligent formation testing platform (IFT) is designed to systematically address shortcomings of legacy technology, enabling focused sampling in the tightest conventional formations. Specialized digital planning of the numerical flow models by adding a brine tracking facility and enumeration initialization was performed to (a) compare and benchmark the cleanup performance of conventional radial 3D probe and new focus radial probe; (b) simulate multiple scenarios including hydrocarbon-water transition to understand the salinity changes while pumping in various water saturation circumstance and optimize operational planning by quantifying cleanup time uncertainties even in two-phase fluid reservoir; and (c) history match the sampling drawdown, flow rate, and salinity change with actual sampling data and provide real-time answers to help accelerate the decision-making cycle.

This dedicated design resulted in increased efficiency in water sampling compared to previous testing done by the operator. Whereas previous gas-water transition zone sampling was challenging because high water-based mud filtrate fractions masked the presence of formation water and formation hydrocarbon, the focused radial probe, combined with state-of-the-art resistivity measurements and prejob modeling of salinity change, allowed identification of gas and the measurement of formation water resistivity in a multiphase flow environment. The formation testing of these low-resistivity-contrast and low-permeability formations enabled acquisition of a 2% contaminated formation water sample in 140 minutes with formation mobility of 1 md/cP. The gas-water zone was confirmed from a dual-flowline resistivity measurement and a hydrocarbon show in mobility of 1.4 md/cP. The intelligent wireline formation testing platform enabled high-performance and efficient collection and identification of formation water and gas in a low-mobility low-resistivity-low-contrast formation.
Automated Hyperparameter Optimization of Convolutional Neural Network (CNN) for First-Break (FB) Arrival Picking
Authors: Ayub Mohammed , Kaka SanLinn Ismail
Published: March 2023

The Convolutional Neural Network (CNN) has been used successfully to enhance the First-break (FB) automated arrival picking of seismic data. Determining an optimized FB model is challenging as it needs to consider several hyperparameters (HPs) combinations. Tuning the most important HPs manually is infeasible because of a higher number of HP combinations to be tested. Three state-of-the-art automated hyperparameter optimization (HPO) techniques are applied to a CNN model for robust FB arrival picking classification. A CNN model with 4 convolutional (Conv) layers followed by one fully connected (FC) and one output layer is designed to classify the seismic event as FB or non-FB. To control overfitting, dropout (DO), batch normalization are used after every two Conv layers, in addition to only the DO layer after FC. The number and size of kernels, DO rate, Learning rate (Lr), and several neurons in the FC layer are fine-tuned using random search, Bayesian, and Hyper Band HPO techniques. The findings are experimentally evaluated and compared in terms of four performance metrics with respect to classification performance.

The five hyperparameters mentioned above are fine-tuned in 13 search spaces for each of the three HPO techniques. From experimental results, applying random search HPO to CNN yields the best accuracy and F1-score of 96.26%, with the best HP combination of 16, 16, 32, and 64 for numbers of kernels in four Conv layers respectively; 2, 2, 2, 5 for the size of kernels in each Conv layer; 0, 0.45, 0.25 for DO rate in each of DO layers; 240 for numbers of neurons in FC layer; and 0.000675 for Lr. In terms of loss on test data, the above combination of HP gives the lowest test loss of 0.1191 among all techniques, making it a robust model. This model outperforms all the other models in terms of precision (96.27%) and recall. Moreover, all HPO models outperformed the baseline in terms of all metrics. The use of DO after Conv layers and FC layers is highly recommended. Moreover, the use of kernel size relatively smaller (i.e. 2) produces the best classification performance. According to the best HP combination results, there is also no harm to use a relatively higher number of neurons in the FC layer than the Conv layer in FB arrival picking classification. The optimal values of Lr range from 0.0001 to 0.000675 depending on the HPO techniques. The model developed in this study improves the accuracy of the auto-picking of FB seismic data and it is anticipated our model to be used more widely in future studies in the processing of seismic data.
New Engineering Approach Using State of the Art RSS to Overcome Complex Colombian Foothills and Improving Drilling
Authors: Hernandez Juan Manuel , Gomez Jose Luis , Lopez Alexander , Garzon Fredy , Celis Manuel , Montes Daniel , Gamba Ivan
Published: March 2023

Drilling in Colombian foothills have been a big challenge since BP drilled on this area in 1987, currently operating by Ecopetrol S.A foothill implementing innovative well design and new technologies. This basin has been characterized by its complex geological conditions, structure full of faults and high stresses that make drilling operation a big challenge.

New well construction engineering based on thorough offset wells and NPT events analysis in addition to the implementation of lessons learned from previous wells in the area, combined with state-of-the-art rotary steerable system have changed the way of drilling in Colombian foothills field overcoming all the challenges faced in the past.

To achieve this success, the following approach was followed: Concatenate well profile to balance dogleg severity to minimize tortuosity to allow running the casing smoothlyInnovative well design to achieve exploration objectives in Cupiagua XD45, a well drilled by Ecopetrol S.A. in 2022.BHA optimization including state-of-the-art rotary steerable system to enhance the drilling performance.Transient finite element simulation for 12 ¼" × 14 ¾" section to determine optimum rotary steerable BHA and underreamer cutting structure configuration to achieve smooth drilling condition and borehole quality.

This integrated approach allowed to: Optimize well trajectory design process achieving lower and concatenated dogleg severities driven by formation dips bedding to avoid wellbore instability problemsOptimum BHA design and stabilization to minimize stuck probability and assure an optimal BHA dynamic while drilling the wellMinimize borehole tortuosity using last generation of RSS system to achieve smooth borehole quality enhancing tripping, drilling, and running the surface casing and intermediate liner, improve drilling, tripping and casing run performance.Simulation and technical analysis to choose the proper bit profile and design correct underreamer’s cutters to run on 12 ¼" × 14 ¾" section to deliver good wellbore quality and allow smooth 11 ¾" × 11 7/8" liner.

This new well construction engineering approach represent an effective solution to overcome Andean foothill challenges achieving optimum borehole quality and improving drilling performance in complex drilling environment by incorporating state-of-the-art RSS
Evaluating Lifting Options Using Multiphase Dynamic Flow Simulation in a Complex Offshore Oil Well - Case Study
Authors: Ayyad Abdelhadi Atef , Arafa Mahmoud Ibrahim , Merghany Ibrahim Aly , Korish Mahmoud , Elrayes Soha , Negm Mohammed Nagy , Rashad Osama Mohamed , Khalil Ahmed Mahmoud , Ahmed Mahmoud Abdelrahman , Youssef Ahmed Hassan , Elwan Mahmoud , Darwish Hatem Mohamed , Hasan Gehad Fawzy
Published: March 2023

This paper presents a case study of using the dynamic multiphase simulator in planning an offshore well. The drilling engineers expected to encounter some issues that would lead to installing a smaller production liner. The use of the five-inch liner would affect the gas lift valves' location and lead to a shallower operating point of injection, which would not have considerable tolerance for the operational parameter's changes and would reduce lifetime and reserves.

Many scenarios were simulated using a commercial dynamic simulator to support operational planning. The scenarios included keeping the well flowing naturally, installing a gas lift system, using a tail pipe string, and a combination of gas lift and tail pipe. The effect of each decision on the well's abandonment pressure was studied using sensitivity and uncertainty and with near wellbore modeling. In addition, the study simulated the restarting of the well after shut-in under several operating conditions. The restarting options included supporting the gas lift with coiled tubing nitrogen lifting considering different types of killing fluid.

Combining the five-inch liner with a tail-pipe string can be used to restore the original well's lifetime. The study saved the company the cost and time of drilling a new hole. The well’s operating envelope was developed at each operational change to ensure stable production while taking the operational constraints into consideration. Complementing the steady-state gas lift design with dynamic testing enhanced the design and improved the standard procedures of the unloading.

This study brings the significance of dynamic simulations in the overall production cycle: planning to operations. Further, dynamic simulations also help arrive at guidelines for the operators on how to avoid failed start-ups and ensure stable operation. The power of integration between different disciplines is shown through the incorporation of several subsurface and surface information in the uncertainty study.
A Novel Approach to Combine Models to Evaluate Interwell Connectivity in a Waterflooded Reservoir with Limited Injection History
Authors: Djanuar Yanfidra , Huang Qingfeng , Adnan Izwan , Lozano Jose , Ameish Giamal , Gibrata Muhammad , Venkatraman Ashwin , Malkov Anton , Davudov Davud , A Rahman Rosmawati , Al-Aulaqi Talal , Dindoruk Birol
Published: March 2023

Waterflooding is one of the most widely implemented enhanced recovery in mature oil fields. In the absence of a reliable reservoir model, waterflood optimization can be a challenge. The availability of continuous recording of production, injection and well data can be utilized to improve reservoir management in this novel approach.

This study presents a new approach using Machine Learning (ML) technique through multiple signal analysis to optimize waterflood operation in a brownfield offshore Caspian Sea. To evaluate injection efficiency on oil production, firstly the interwell connectivity between injectors and producers are determined. However, because of the complexities associated with the reservoir and the data, it has been achieved through analyzing various available signal types which are informative and responsive to injection rates. Results obtained from multiple signals are then aggregated to identify the injector-producer pair connectivity. Next, production well performances are evaluated through multiple diagnostic models. Finally, the impact of injectors on oil production rates are analyzed and injector efficiencies are determined to establish a more efficient waterflooding strategy.

The proposed methodology has been applied to a reservoir with around 50 producers and 7 injectors. The interwell connectivity between pairs have been identified and ranked. Using data analytics techniques on multiple surveillance data sets, the analysis of the waterflood is achieved more swiftly and accurately. It was observed that for this specific case, the most informative signals that help determine connectivity are the water cut, and water production rate. The identified injector-producer connections obtained from these models were further verified and compared well with additional available surveillance data on tracers for this reservoir. Understanding these leads to devising optimum waterflooding strategies such as diverting more injection water to the more efficient injectors and less injection water to the inefficient injectors.

A novel multi-signal analysis using ML techniques is proposed that combines multiple data being collected as part of surveillance. The presented approach can be extended to similar waterfloods to help with optimizing the waterflooding strategy. This new approach helps with current digitization strategies in oil companies that seek to obtain faster and consistent solutions to accelerate decision making and as an alternative to cases especially where reservoir model is poorly defined.
Production Data Diagnostics based on Inflow Performance Relationship of pumping wells in CBM Fields
Authors: Bhide Sarang , Jain Rajesh , Srivastava Priyank , Fife Dustin
Published: March 2023

Coal Bed Methane (CBM) is a type of unconventional resource wherein methane gas adsorbed on surface of coal seams is produced by dewatering waterfilled coal seams and thereby causing desorption of the gas. This paper aims at applying quick look diagnostic curves to assess performance of Coal Bed Methane (CBM) wells which traditionally encounter high frequency workovers with reservoir heterogeneity and complex physics. Currently, very few production diagnostic tools are available to access / predict unconventional Coal Bed Methane (CBM) well behavior. Use of production diagnostic curves using pressure-rate data is presented to distinguish the well performance with variety of completion types and artificial lift strategies which provides gainful insights into relative well performance. Inferences could be used to plan / optimize for future development strategies for infill drilling. Response based diagnostic tools are derived using P-Q (Pressure-Rate) and PI-Cum. (Productivity Index - Cum. Prod.) plots and extrapolation of trends can be used to guesstimate the expected ultimate recoveries and drainage area for CBM wells. Thus, typical characteristics of these performance plot gives clear indication of qualitative desorption front. Diagnostic P-Q and PI-Cum. performance curves were generated for various on-stream CBM wells and these curves were used to identify and predict the flow regime in wells with different completion scenarios. Single phase Inflow-Performance Relationship (IPR) shows a typical behavior in most of the wells and analysis of life-cycle IPR indicates a characteristic signature for on-set of pseudo-steady state (PSS). Flow regimes which can be clearly identified are initial flow i.e. Infinite acting radial flow (IARF), completion/intervention dependent flow and PSS flow. The initial flow period involves dewatering of coal seam and hence generates a hyperbolic curve on the p-q plot. As desorption front advances further, peak gas production is observed and this phase can be prolonged by effective use of Artificial lift (AL) strategies to maximize the drawdown. The well soon shows positive slope line on IPR that corresponds to Pseudo-steady state or Boundary dominated flow. At this juncture the drainage boundary of the well is properly defined and so is the Expected Ultimate Recovery (EUR). This phase is the longest in terms of well life cycle. These diagnostic tools were highly useful in well and reservoir performance analysis to optimize the AL and workover practices for CBM wells. This paper brings out novel approach towards analysis of production data from CBM field with wells operating on Progressive Cavity Pumps (PCP's) to dewater coal beds, it brings out a way to qualitatively estimate the desorption front and quantitatively deduce the EUR’s of the wells. This paper proposes a way to generate "Type well" analysis for CBM field and augment a reliable production forecasting.
Benchmark Drilling Performance in the Undrillable Complex Fold Belt Area
Authors: Memon Hizbullah , Jingbin Mei , Agha Ghulam Nabi
Published: March 2023

Alpha Field, a fold belt Oil & Gas field located in the Kirthar mountainous range, has remained as one of most problematic drilling terrains of Pakistan and had been once termed as an undrillable prospect considering the multiple sidetracks at previous wells. Due to formation challenges and multiple sidetracks. One of offset wells had been abandoned because of not reaching to reservoir target and other offset well was eventually reach to well TD after three sidetracks and incurred heavy costs.

This paper discusses the case study of phenomenal drilling performance at Well-3 in Alpha field which includes extensive well engineering data reviews to achieve operational excellence. A very detailed offset review has been prepared followed by generation of well plan after careful selection of the drilling plans which included drill bits designs, BHA selections, drilling practices, drilling fluids performance targets, drilling rig performance and extensive level of vigilance to deliver the most complex well with best of the class benchmarking in the field as compared with previous wells and surrounding fields of similar sub-surface challenges.

The detailed Well Design and Engineering together with technological selection purely application-based enabling to deliver a successful Alpha field well, both in terms of the lowest cost and in terms of time as the fastest well in Alpha field.

The Alpha field due to its complexity, lower success rates and higher costs was one of the most challenging assets in terms of drilling and production delivery. With excellent drilling performance at Well-3 and good production results has opened more opportunities for the Alpha field, and more wells are being planned in the upcoming time.