bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overcoming Formation Stability Risks and Optimizing Drilling Time using Continuous Circulation System (CCS) for the First Time in the Colombian Foothills
Authors: Moncada J. , Zuleta O. , Tovar J. , Bacca M. E. , Martinez M. , Duran W. , Salcedo C. , Bastos H. , Moreno G. , Cuevas N. , Ospina J. M. , Martinez M. , Gutierrez J. , Ayala L. , Rueda M. 
Published: February 2024

Abstract
The largest oil and gas operator in Colombia often faces challenges when drilling in the Llanos Foothills oilfield because of the area's complex geology. Issues typically occur in the Carbonera Coal formation, which is characterized by the presence of fractures with equivalent coal permeabilities and high-pressure fluctuations during conventional drilling operations. These characteristics create operational complications, such as stuck pipe caused by cuttings and difficulty during wellbore cleanout caused by cuttings decantation or caving when circulation stops (Fig. 1).
Continuous circulation systems (CCS) help mitigate undesired wellbore geometrical effects and potential packoff during connections, which can save rig time and generate additional benefits, such as cooling of the measurement while drilling (MWD) tools and maintaining bottomhole pressure (BHP) control during drillpipe connection.
By using a CCS in the Llano Foothills, the operator reduced the operation by seven days and total capital expenses by 1.05%. Additionally, sidetrack drilling was avoided, which saved time and helped reduce carbon emissions by 204.9 TCO2e with no health, safety, or environmental (HSE) incidents.
The first implementation of this CCS in Colombia is discussed and highlights a novel way to plan and execute drilling projects with the geological components of the Llanos Foothills. This technology was successfully used in the C7 and C8 units of the Carbonera Coal formation and could potentially be used in other areas of similar complexity.
How Corporations Succeed by Solving World's Toughest Problems - Tackling Climate Change with an Elite Business Research Consortium and AI-Enhanced Leadership: Decision-Making Endeavor in the Face of Climate Change
Authors: Uddin Ali Khan Muhammad Affan , Louis Clifford , Manzoor Abdul Ahad , Ali Syed Imran , Laliji Shaine Muhammadali , Aun Ali Syed Muhammad , Haneef Javed , Abbasi Faiq Azhar , Khan Muhammad Sami , Tirmizi Syed Talha , Kamran Muhamad 
Published: February 2024

Abstract
This study aims to contribute to the success of corporations in addressing global challenges, specifically focusing on climate change. The primary objective is to enhance the heat resistance capabilities of materials crucial for geothermal energy extraction, a key renewable energy source with minimal carbon footprint. Presently, Iceland leads in global geothermal energy production, emphasizing the significance of optimizing extraction methods. Previous research faced challenges due to suboptimal material selection, hindering drilling to greater depths. This study proposes a novel solution—employing innovative material coatings on drilling bits and pipes, utilizing metallic compounds with exceptional heat resistance properties. The coating strategy involves leaving pipes uncoated up to a depth where they naturally withstand heat, with subsequent application for greater depths. This approach promises cost-effective materials capable of enduring extreme conditions in geothermal drilling, fostering higher drilling depths and cost efficiency. Implementation projections suggest significant facilitation of geothermal energy extraction, particularly in abandoned wells near tectonic plate boundaries, reducing extraction costs. The study underscores the societal benefits of tapping into indigenous renewable energy sources, emphasizing the minimal carbon footprint of geothermal energy. The proposed material-coating approach aligns with global efforts to combat climate change and presents a strategic decision-making endeavor for corporations to contribute to environmental sustainability.
Unconventionally Hydraulic Fractured Wells to Develop a Tight Sour Oil Reservoir a Case Study from Oman South
Authors: Harrasi A. M. Al , Kalbani M. Al , Ouyang Y. , Al-Khusaibi A. , Tobi K. M. Al , Lefeber T. , Smirnov D. , Al-Shabibi A. , Al-Jarradi S. , Harrasi A. J. Al , Ghammari A. Al , Saadi Z. Al 
Published: February 2024

Summary
This paper summarizes the integrated technical learnings from success with unconventional hydraulically fractured producers in a tight silicate reservoir located in Southern Oman. It shows the results and development challenges from a project to extend the proof of concept into further field development, maturing commercial volumes, and meeting the project’s value drivers. The producing reservoir is more than 3,000 m deep, encapsulated in salt and over-pressured. It contains light, sour oil with H2S/CO2 contents of 1 and 2 mol%, respectively.
Two wells were fracked with unconventional fracs as a new trail to the field. Previous wells were completed with conventional fracs. The result was used to formulate a phased development plan and define optimum subsurface decisions. Frac parameters were matched in Ghofer using actual pumping data. Dynamic Compute Modelling Group models with frac models were then used to match well test and PLT results. These models were subsequently used to generate production forecasts and defining the optimum subsurface decisions such that the project remains cost-competitive within the company’s project portfolio.
The two first unconventionally fracked wells show promising results in this tight sour reservoir. Unconventional fracking created longer fractures than conventional frac mainly due to less fracture damage and proves to deliver economic and competitive oil rates. Guar-based gel creates thicker shorter fractures. High-Viscosity-Frication-Reducer (HVFR) creates thinner and longer fractures. With unconventional fracs, the number stages were increased versus conventionally fracked wells, increasing reservoir coverage by factor three compared to conventionally fracked wells, and producing five times more oil rate at higher Tubing-Head- Pressures. Optimal Unconventional frac design and well spacing and number were evaluated jointly. To further optimize frac design, along term trial plan will be implemented. The study shows that factors such as matrix permeability, frac heigh and half- length mainly impact recovery. The project went through multiple project milestones to evaluate and optimize the development and select optimum project decisions that best meet the project’s value drivers. The team optimized well number, placement & frac design, material, and completion.
This paper discusses the unconventional frac result in a sour reservoir with all related challenges and project decisions. The authors have summarized the results from the successful unconventional frac, and field development decision related to the subsurface, frac and well designs that should be taken in an integration way. The study outcomes can be learnt from and replicated in similar sour tight reservoir fields.
Well Placement Optimization for Avoiding Caves Using GANs and POMDPs
Authors: Kanfar Rayan , Halabi Lama El , Hall Tyler , Mukerji Tapan 
Published: February 2024

Abstract
Exploration for subsurface resources, such as groundwater and hydrocarbons, involves a high degree of uncertainty. This is because the spatial distribution of targeted resources and the geology of their overburden is largely unknown. In some areas, eogenetic caves known as banana holes overlay targeted resources. Because of pressure loss, drilling into these caves causes operational hazards that lead to project delays, well abandonment, and even loss of life. The goal of this paper is to formulate well placement as a sequential decision-making problem and solve for an artificially intelligent agent that avoids drilling into these types of caves. We formulate the decision problem as a partially observable Markov decision process (POMDP). To model the spatial uncertainty of caves, a Generative Adversarial Network is used. The generative model is trained based on a Light Detection and Ranging survey from San Salvador Island, Bahamas. To solve for a policy that recommends drilling actions, the Fast Informed Bound algorithm is explored. The proposed sequential approach for well placement is shown to recommend a sequence of actions that avoids drilling into caves and demonstrates the potential of POMDPs in this problem.
Case Studies of a Novel Digital Twin System for Real-Time Early Identification and Warning of Pipe Stuck
Authors: Zhang Jiawei , Wang Qing , Zou Lingzhan , Yu Jingping , Li Jijun , Yang Yun , Zhang Yang , Zhao Zhixue 
Published: February 2024

Abstract
Pipe stuck serves as one of the primary downhole accidents in drilling industry with consequences ranging from minor inconvenience to severe complications. Despite the variation on its cause and mechanism, this downhole accident could be prevented or avoided based on early identification of its unique symptom or data behavior, provided intervention or remediation measures are taken promptly. While conventional prediction or recognition methods, which rely on the fluctuation amplitude and curve trends of surface drilling parameters, are subject to user experience and human error, it's often the case that their timeliness cannot be guaranteed.
A novel digital twin system, based on the deviation of hook load, torque and SPP (Standpipe Pressure) from theoretical modeled values and ROC (Rate of Change) of these three actual parameters, is developed for real-time early identification and warning of pipe stuck while drilling. A PSRI (Pipe Stuck Risk Index) ranging from 0%-100% is proposed based on ROC and deviation for comprehensive evaluation regardless of drilling state. Both T&D and wellbore hydraulics models are adopted to model the theoretical hook load, torque and SPP within preset computing cycle. ROC and deviation thresholds, corresponding to three different risk levels as low (green), medium(yellow) and high(red), were obtained by using RFA (Random Forest Algorithm) based on data of historical wells with and without pipe stuck accidents.
Preventive or intervention measures are generally mandatory for on-site personnels or engineers once high-risk (red) alert is identified by the system. Several case studies are outlined to exhibit that the occurrence of pipe stuck accidents could be detected typically between 30 minutes and 2 hours ahead during back-reaming and tripping operations, which proved its potential for early identification and prevention of this downhole accident in real-time drilling.
Cost containment and operational efficiency could be created with system implementation as it helps to reduce analysis time and provide timely proactive action in real-time monitoring, which demonstrates that digital twin driven technique could better capture and utilize digital data to minimize NPT and optimize drilling.
Channel Characterization in Sandstone Formation Using Pressure Transient Analysis - A Practical Overview to Define Geological Attributes
Authors: Alawami Rahmah L. , Tello Gomez Adan H. , Moreno Sierra Ferney G. , Brohi Imad 
Published: February 2024

Abstract
Understanding reservoir systems is of significant importance in optimal exploitation, development plans and management strategies. Sandstone reservoirs consisting of stacked channel deposits are known for their heterogeneity and varying depositional facies adding to their complexity. This paper will focus on the characterization of sandstone reservoirs in channel environments using pressure transient analysis coupled with seismic attributes and stratigraphic features.
Proper channel mapping and precise predications of the spatial distribution of sand bodies is a challenging process. Pressure transient analysis can identify the existence of channel features, reservoir properties, extent of formation properties, and boundary conditions. However, linear flow identified in well tests does not predict the direction of these channels. The proposal integrates both static and dynamic reservoir data along with regional geological interpretation which plays a vital role in the proper characterization and modeling of these channel systems.
The findings of this study enrich a deeper reservoir understanding of the structural features’ extent, continuity and connection. Different pressure regimes were observed in both vertical and lateral directions showing the complex heterogeneity in between layers and irregular channel distribution patterns. This response is similarly exhibited in the reservoir flow capacity which resulted in abrupt shifts in reservoir characteristics as evident in the acquired pressure transient data. It is proposed to revise seismic attributes and the use of stratigraphic core data to validate the conceptual connections between this complex channel system. In addition, findings are used to re-distribute formation properties in order to improve future reservoir models.
The combined use of dynamic and static data improves the regional interpretation of challenging sandstone systems. Adequate understanding of the spatial distribution of the sand facies and reservoir properties ensures effective well placement and development strategies.
Customized Drilling Fluids Solutions for Challenging Geothermal Wells
Authors: Olivares T. 
Published: February 2024

Abstract
Geothermal wells are very challenging to be drilled due high temperature and the associated risks that involve this type of wells. In order to find the adequate solutions for the drilling fluid challenges on those type of wells, we did an extensive lab evaluation on multiple formulations, where we used our approved drilling fluids additives portfolio to customize the required water-based fluids (WBF) and invert emulsion fluids (IEF) formulations for high temperature wells. Wide lab testing on multiple WBF and IEF formulations were performed In-house, simulating the harshest conditions to properly customize the drilling fluids solutions for a Geothermal wells campaign. However, before start these geothermal wells campaign and after successfully lab testing verification, those formulation were implemented at the field in wells with Bottom Hole Static temperature (BHST) from 330°F (165°C) up to 450°F (232°C). Similarly, those drilling fluids were used to successfully drill, log and core across those challenging environments without any issue related to the thermal stability of the drilling fluids additives.
In some of the wells, WBF was essential due logging requirements, for those wells, we relied on improved synthetic polymer thermal stable up to 475°F (246°C) to control the fluid loss, with the addition of temperature stabilizers and oxygen and H2S scavengers to optimize the polymers thermal stability. Also, we did utilize Causticized Lignite (CL) and chrome free methyl ester of sulfonated tannin (CFMEST) for better results as thinner and to help to control the fluid loss. Another fundamental additive in the formulation was the pre-hydrated bentonite used to enhance the suspension properties to avoid barite sag issues and to enhance the hole cleaning.
Other wells were drilled with similar conditions for the Geothermal wells using IEF, for this type of fluid, efforts were established to formulate an innovative solution to the challenging high-temperature conditions in the studied area. The issues addressed included hole cleaning, hole instability for a narrow mud-weight window and reservoir damage. The strategy was based on the synergy of combinations between polymeric packages, emulsifiers, and filtration reducers of the engineered IEF formulations to build stable fluids and afford tight emulsion and fragile gel properties with minimal filtrations to the formations.
As conclusion, we were able to customize Drilling Fluids Solutions for the multiple’s challenges expected during the Geothermal Wells operations. The excellent performance of those customized WBF and IEF formulations were delivered through use of novel emulsifiers chemistry, customized polymeric additives, innovative temperature stabilizers and a new multi-functional additive for narrow margin conditions, in preparation for this wells campaign.
Increasing Oil Production With Jet Pumps by Reducing Pressure Losses in the Jet Pump-Sliding Sleeve Coupling
Authors: Soria J. , Izquierdo A. , Córdova F. , López B. 
Published: February 2024

Abstract
The pressure losses in the jet pump–sliding sleeve coupling were calculated for the typical completions of wells that produce using hydraulic pumping in the Ecuadorian oil fields. A new jet pump was designed to minimize losses. The field test results showed a significant increase in well production compared to those obtained with a conventional jet pump. Several studies have proposed improvements in jet pump efficiency by optimizing the nozzle, throat, and diffuser geometry. However, they have not considered possible flow restrictions once the fluid leaves the jet pump and goes through the sliding sleeve where the pump is seated. Therefore, computational fluid dynamics (CFD) simulations were performed to analyze the flow through the pump–sliding sleeve coupling in completions with 3.5 in. tubing string and 3.5x2.81 in. sliding sleeves. The simulations were run for different discharge flow rates from the outlet of the pump diffuser to the entry into the annular space. Excluding the characteristic energy losses of Venturi systems, the largest pressure losses were found in the flow through the pump-sliding sleeve coupling. This is because the pump discharge is located below the ports in the sleeve, and to reach the annular space, the fluid must pass through narrow conduits generated by the closing sleeve. Pressure losses in this zone are greater than 40 psi and increase with discharge flow. With these findings, the jet pump was redesigned to align the discharge flow with the ports in the sleeve and minimize pressure losses. The new design was installed in the X1 well of the Ecuadorian state oil company, which was producing 2,318 BLPD with a conventional jet pump. The new pump was installed with the same nozzle-throat combination and was driven with the same hydraulic power. The reduction in pressure losses in the pump-sliding sleeve coupling resulted in a 9% increase in the production of the well. Sliding sleeves were not designed to hold jet pumps. Although this practice has facilitated reestablishing the production of wells with hydraulic pumps using the existing completion, the inefficiency of the pump-sliding sleeve coupling would not allow the productive potential of the wells to be realized. The new jet pump presented in this article eliminates these problems.
Novel Application to Estimate Cement Quality by Means of Elemental Spectroscopy Data
Authors: Tanjung Heri , Al-Fawwaz Abdullah A. , Ghonim Elsayed Ouda , Tran Han Ngoc 
Published: February 2024

Abstract
Pulsed neutron log (PNL) is well known for its main application to determine hydrocarbon saturation in cased-hole wells by means of neutron inelastic reaction with carbon and oxygen elements. However, the computed hydrocarbon saturation might be biased by the presence of hydrocarbon in the annulus between casing and formation, in which the cement is not evenly distributed. Cement quality analysis is important to complement the cased-hole analysis, not only to ensure the validity of the computed hydrocarbon saturation but also to provide valuable insights in term of drilling and workover to take necessary action in ensuring zonal isolation between reservoirs.
Despite the available technology for cement evaluation, elemental spectroscopy reading from PNL can also be used to give an insight about the cement quality in the annulus since the emitted neutrons from PNL also interact with other elements in the formation and near borehole environment such as silicon, calcium, iron, magnesium, etc. which can be detected and quantified in term of count rate. The quantification of inelastic response between emitted neutron and calcium nuclei from PNL can serve as an indicator to define cement quality in annulus.
This paper explains the proposed technique to determine the cement presence by utilizing the elemental spectroscopy reading of calcium since typical elemental composition of cement is dominated by calcium. First, the zones with good cement condition and engaged wellbore need to be defined from CBL and caliper data as reference zones. Then, elemental spectroscopy reading of calcium over these reference zones is used to create the estimated standard calcium spectroscopy response for the whole interval with the same completion feature. Poor cement quality or lack of cement volume is indicated whenever the actual calcium spectroscopy reading is significantly less than the estimated standard calcium spectroscopy response. The result is then validated using the available conventional cement evaluation log such as cement bond log (CBL) and variable density log (VDL).
This proposed technique shows satisfactory result in most of the observed intervals. However, it is suggested to perform this technique using multi-arm caliper in order to better simulate the annulus volume for cement identification using down-hole spectroscopy data. It is also advised to utilize the latest generation triple-detector pulsed neutron log to obtain more precise elemental spectroscopy measurement.
Offshore Geothermal: A Major Resource for a Stressed Planet
Authors: Bolton Rebecca , Crossley Rob , Fowler Alex , Peter-Borie Mariane , Drumm Elisha , Williams Mark 
Published: February 2024

Extended Abstract
The IPCC's AR6 Synthesis Report issues a stark warning, emphasizing that the world's current efforts to combat climate change fall short in terms of pace and scale (IPCC 2023). As per the IPCC's assessment, the primary pathways for mitigating energy emissions until 2030 involve the continued expansion of wind and solar energy. Additionally, there is significant potential to reduce methane emissions during the extraction and use of fossil fuels, as well as to capture and store carbon emissions. The report also highlights other energy sources that could be scaled up without directly contributing to emissions by 2030. These include bioenergy with carbon capture and storage (BECCS), hydropower, nuclear power and geothermal energy.
Geothermal energy holds a unique advantage as it offers both heat and power generation capabilities, along with the potential for creating a variety of cascading uses. While geothermal energy is a proven and reliable baseload resource on land, its commercial development often faces challenges related to subsurface geological complexity. Onshore geothermal also faces problems of scalability due to the variable subsurface distribution of heat and permeability capable of delivering sufficient energy for power production.
At CGG, we have undertaken research into the possibility of expanding geothermal energy beyond our current technical and geographic boundaries in the long term. This paper is intended to draw the attention of geoscientists, businesses, and policymakers to the substantial, and more consistently distributed, geothermal resources available globally in offshore settings, with a particular focus on the Red Sea region.