bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Data Driven Approach of ROP Prediction and Drilling Performance Estimation
Authors: Han Jiahang , Sun Yanji , Zhang Shaoning 
Published: April 2019

Abstract
Given the expense of drilling in resource development, explore the optimal drilling operations, especially improve the rate of penetration (ROP), has become increasingly important. The prediction of ROP is challenging due to the complex bit and rock interactions. Several experience based models have attempted to predict ROP, but few of them can have excellent estimations.
In this paper, a new ROP prediction methodology is developed using machine learning techniques. The booming computation capacity and large volume of data provide a new way to solve the problems. In this paper, wells from southern China have been used to demonstrate our approach. Well logging, mud logging data, geological information, daily well reports, and many other data have been included for the model development. Parameters which have been previously considered irrelative to ROP calculation show their impacts in the model.
The machine learning approaches bring new insights into the ROP prediction. Comparing with the conventional approach, our method consider drilling as a continuous procession. ROP at current time relates to the drilling rate in previous time step. In our case, the model improves ROP estimation accuracy. In addition, engineers can use this tool to arrange better drilling plans during operation. Dive deep into the data, the acceleration and deceleration of ROP showed close relationship to WOB and mud properties, improve the mud rheology and operation strategies can keep the ROP in a optimal range which may enhance the drilling efficiency.
With the assistance of machine learning techniques, a new method of ROP prediction has been developed. Comparing with the conventional approaches, this method considers more parameters and improves accuracy. Factors that may enhance the drilling bit performances were also explored. This new data driven method can be beneficial for drilling efficiency.
An Integrated Approach to Well Leak Diagnostics: Case Study of the Successful Application of the Latest Leak Detection Technology and Interpretation Offshore Timor Sea, South East Asia
Authors: Imrie Andrew , Negenman Brendon , Lee Chung Yee , Iyer Mahadevan S. , Parashar Sarvagya , Shata Mohamed Raouf , Helton Sean 
Published: April 2019

The identification of low-rate leaks along with low annular-pressure buildup rates in any type of completion presents challenges in the well-integrity domain. This paper emphasizes the importance of understanding the well-diagnostic problem to determine feasibility, isolate interest zones, enhance stimulation strategies, and ultimately optimize the acquisition of high-resolution acoustical data from the wellbore with a latest-generation advanced leak-detection tool.
This case study discusses the methodology that underlies the successful determination of the depths and the radial locations in the outer casing strings of multiple leaks in an offshore well. In the study presented, emphasis had been placed on the job planning to provide adequate or substantial leak stimulation for the accurate determination of the leak points in terms of radial distance away from the tool axis within the wellbore. Rather than a shut-in and flowing or venting acquisition, it was proposed that the optimal method for the successful determination of an outer casing string leak involved invoking a range of flow rates and, therefore, acoustic levels, across an extended period. The study also demonstrates the advantages of integrating acoustic-based tools with conventional production logging tools.
Two outer string casing leaks with annulus to formation communication areas were identified from high-resolution leak-detection logging coupled with conventional pressure and temperature measurements. The interpretation process included the computation of a 2D radial map of the flow activity across each zone of interest. This process resulted in less ambiguity and clearer results obtained in real time during the acquisition. The location of each leak point was triangulated using an error-minimization algorithm from the received acoustic waveforms at the tool receiver array. Further, the optimized stimulation strategy enabled leak-stimulation responses to be tracked in the computed power spectral density (PSD) at each leak. This process enabled the operator to promptly move on with the well abandonment strategy without waiting for further data analysis.
Attention to detail from the outset and a complete understanding of the well and its annular pressure and fluid behavior enabled an optimized and focused electric line diagnostic strategy to be used. The use of high-resolution acoustic data from an advanced leak-detection tool with an array of hydrophones ensured that the multiple leak locations were identified and characterized.
New Insights in the Characteristics Required for A Successful Flowback Surfactant and Its Use in Tight and Unconventional Reservoirs
Authors: Rabie Ahmed , Zhou Jian , Qu Qi 
Published: April 2019

Abstract
Hydraulic fracturing has always been associated with significant volumes of fracturing fluid invading the formation matrix, which leads to water blockage and a reduction in relative permeability to gas or oil. In Shale and tight formations, this has become more challenging since capillary forces have profound impact on water retention and hence, water recovery and subsequent oil productivity. Surfactants and microemulsions have been extensively reported as flowback additives to lower surface and interfacial tension to maximize water recovery.
Most of the previous studies focused on a few testing methods to validate a surfactant or a microemulsion formulation for flowback use. In this work, a new environmentally friendly water-based surfactant formulation (Surf-I) was evaluated for flowback and its performance was compared against several industry standards of microemulsions and non-ionic alcohol ethoxylated surfactant. Surface tension (ST), interfacial tension (IFT), contact angle (CA), and coreflood tests were conducted in a wide range of typical field conditions of water salinity, temperature, crude oil type, and surfactant concentration. Core flow testing on 0.1-0.3 md Kentucky sandstone was conducted simulating oil reservoirs following constant-pressure flow schemes of 50-500 psi. Water recovery and oil productivity were determined for each pressure stage.
The new formulation showed a surface tension of 26 mN/m with CMC corresponding to a load of 0.1-0.3 gpt, depending on the water salinity. Interfacial tension measurements varied from 0.17 mN/m to 10 mN/m, depending on the crude oil type and temperature. Contact angle measurements indicated the surfactant ability to water-wet controlled substrates. The coreflood results confirmed the benefit of using surfactants for flowback versus non-surfactant cases, especially at low- to mid-pressure flow and. At 50 psi pressure difference, no oil was observed in the no-surfactant case. At 100, 250, and 500 psi the oil productivity with surfactant was 53, 22, and 20% higher than the base case. The results also showed that a formulation with ultra-low IFT (5E-2 mN/m), can initially recover substantial water volume but did not show a superior performance over the new formulation. The data obtained in this study can be used to identify the optimum criteria of a flowback additive in terms of surface tension, IFT, and wettability requirement to enhance water recovery and maximize oil productivity.
Advanced Modeling of Production Induced Pressure Depletion Impact on Infill Well Using Cloud Computation in the Haynesville
Authors: Zheng Wei , Xu Tao , Baihly Jason , Malpani Raj , Li James , Zhang Rui 
Published: April 2019

Since late 2017, the Haynesville Shale has seen an uptick in activity as more operators have started to drill more new shale wells than at any other time since the industry was slowed due to declining oil price at the end of 2014. Some of the new activity has been focused on pushing the economic boundaries of the Haynesville shale out whereas others have focused on drilling infill wells or wells that are drilled between pre-existing wells (known as "parent wells"). Parent wells may cause pressure depletion in the reservoir, potentially hindering the performance of new infill wells. The distance from the parent well to an infill well along with the degree of reservoir depletion caused by the parent well impact, to varying degrees, the production results of the infill wells. It is important to design a completion program in the infill well that minimizes the potential negative impact of depletion. This paper presents detailed studies assessing the impact of the change in offset well spacing and reservoir depletion related to parent wells on infill well performance through modeling in the Haynesville shale.
An actual reservoir dataset was utilized in the Haynesville shale to build the parent well hydraulic fracture and reservoir simulation models to account for fracture calibration and production history matching. The models' results were then used to evaluate the impact of production depletion on the stress reorientation and changes in stress magnitude through a coupled boundary element and finite element model residing in a geomechanics simulator. Three different production depletion times were modeled through the simulation, 0.5, 1, and 3 years, to understand the timing impact on the infill well production. After the stress in the model was updated for each case, a child well pad was added to the model adjacent to the parent well. The well spacing, stimulation job treatment, and fracture stimulation pump rates were all varied for child well simulation and evaluated to understand their impacts on the created complex fracture propagation and total system hydrocarbon recovery.
In this study, more than 200 different scenarios were simulated by using cloud computation, and each parameter was compared for varying spacing scenarios for the three depletion time horizons. This study can help the understanding of well spacing, completion job design, and reservoir depletion impact on the new infill well performance and help the optimization of the infill well completion strategy to achieve optimum production performance for new infill wells and minimize communication or fracture hits to the existing parent wells in the Haynesville.
Modeling Interwell Interference Due to Complex Fracture Hits in Eagle Ford Using EDFM
Authors: Fiallos Mauricio Xavier , Yu Wei , Ganjdanesh Reza , Kerr Erich , Sepehrnoori Kamy , Miao Jijun , Ambrose Raymond 
Published: April 2019

AbstractShale field operators have vested interest in optimal spacing of infill wells and further fracture optimization, which ideally should have as little interference with the existing wells as possible. Although proper modeling has been employed to show the existence of well interference, few models have forecasted the impact of multiple inter-well fractures on child wells production to optimize further hydraulic fracture designs. This study presented a rigorous workflow for estimating the impacts of spatial variations in fracture conductivity and complexity on fracture geometries of inter-well interference. Furthermore, we applied a non-intrusive embedded discrete fracture model (EDFM) method in conjunction with a commercial black oil reservoir simulator to investigate the impact of well interference through connecting fractures by multi-well history matching, based on a robust understanding of fracture properties, real production data and wellbore image logging. First, according to updated production data from Eagle Ford, the model was constructed to perform four (parent) wells history matching including five inner (child) wells. Later, fracture diagnostic results from well image logging were employed to perform sensitivity analysis on properties of long interwell connecting fractures such as number, conductivity, geometry, and explore their impacts on history matching. Finally, optimal cluster spacing was recommended considering interwell interference. The simulation results show that well interference is present and reduces effectiveness of the fracture hits when the connecting fracture conductivity, primary fracture conductivity, and number of connecting fractures increase. Because of these interwell long fractures, the bottomhole pressure behavior of the parent wells tends to equalize. Furthermore, the EDFM application is strongly supported by complex fracture propagation interpretation from image logs through the child wells in the reservoir. Through this study, three possible scenarios are shown with robust history matching of the model considering more than 20 complex dominant long interwell fracture hits and more than 2000 hydraulic fractures.The model became a valuable stencil to decide the well location and spacing, the completion staging, and to optimize the hydraulic fracture treatment design as well as its sequence so that it can be expanded to other areas of the field. The simulation results were applied to the field successfully to afford significant reductions in offset frac interference by up to 50% and reduce completion costs up to 23% while improving new well capital efficiency.
Experimental Study on Surface Frictional Behavior of Materials for Lost Circulation Control in Deep Naturally Fractured Reservoir
Authors: Xu Chengyuan , Yan Xiaopeng , Kang Yili , You Lijun , Zhang Jingyi , Lin Chong , Jing Haoran 
Published: April 2019

Abstract
Plugging natural fractures with lost control materials (LCMs) is the common method to prevent foramtion damage and control fluids loss in In naturally fractured reservoir. The plugging zone strenfth stability is critically important for maintaining long-term plugging quality. Surface friction coefficient (SFC) is proposed as an important parameter for the selection of LCMs based on based on granular matter mechanics and the instability of plugging zone. The force chain network with specific geometry is the basis of the plugging zone strength and supporting external load. The likelihood of shear failure can be increased by decline of SFC. And high strength of force chain can not be formed and it can relatively easy to be broken even if a small shear is applied. Effects of LCMs particle size distribution, circulation abrasion, LCMs combination, working fluids infiltration, and high temperature aging on friction behaviors are analyzed for LCMs with high SFC selection. Results show that the average SFC shows a decreasing trend with the particle size reduction and the difficulty of particle dislocation decreases with the particle size reduction. For deep naturally fractured reservoirs, particle size will degradate due to long-term drilling fluid circulation in the wellbore, thus affecting the plugging effect of drill-in fluid. The mixture of elastic material and fiber into rigid material increases the SFC and elastic material contributes most to the increasing the SFC. The SFC decreases under the condition of fluids infiltration, and the SFC show a higher decline in oil-based condition. The high-temperature aging makes the edge of the organic rigid material more smooth, which reduces its SFC.
Converting Waste Vegetable Oil to Emulsifier for Invert-Emulsion Oil Based Mud
Authors: Ramasamy Jothibasu , Amanullah Md 
Published: April 2019

Abstract
Primary emulsifiers are an integral part of an invert emulsion (water in oil) oil based mud system. These are a class of long chain fatty acids and their derivatives. Primary function of an emulsifier in invert emulsion invert emulsion oil based mud system is to minimize the interfacial tension (IFT) between water and oil to have a stable emulsion which is an important quality of oil based mud. Water droplets are surrounded by these long chain fatty acids like an encapsulation. Fatty acids have hydrophilic head group and hydrophobic head group. The hydrophilic end groups are in contact with the surface of water droplets while the hydrophobic tail groups extend into oil phase thereby forming an osmatic cell. Only water can pass through the osmatic cell wall but not salts. Tall oil fatty acid (TOFA) are the most widely used commercially available emulsifiers which shows excellent emulsion stability even at harsh conditions such as high temperature and high pressure. TOFA is a by product of paper industry. Vegetable oil is also a good source of fatty acids present in the form of triglycerides of saturated and unsaturated fatty acids of varying carbon chain lengths. Our focus on this work is to utilize the abundant availability of used cooking/vegetable oil available for the application of emulsifier by chemical modification. A comparative study has been carried out by formulating invert-emulsion OBM using commercially available emulsifier and the emulsifier derived from used cooking/vegetable oil. The performance of emulsifier developed from waste vegetable oil has been discussed in detail.
Minimise System Upsets in High Oil Production Facility throughout Demulsifier Chemical Trial
Authors: Scarborough James , Mega-Franca Leonardo , Ibrahim Mohamed 
Published: April 2019

Abstract
Process upsets in high oil production facilities can hinder optimal plant performance and result in system shut-ins. Based on several successful demulsifier chemical trials, scientists and engineers have developed a guideline on how to optimize production throughout the chemical trial period. Factors such as chemical injection rate, export crude oil monitoring (basic sediment and water (BS&W) and salt), discharge water quality(from the water-oil separator (WOSEP)), and transformer voltage fluctuation (dehydrator and desalter) plays an important role in minimizing the system upset.
Prior to chemical trial, scientists and engineers analyze the process system to understand individual vessel functions and limitations. Incumbent chemical program provides baselines and key performance indicators (KPIs) set minimum oil specifications before exporting oil to refineries. Demulsifier injection rates are reduced based on the chemical program optimization proposal until it reaches the dosage limit while maintaining stable process throughout the trial. Therefore, scientists and engineers may evaluate the demulsifier’s performance based on the KPIs set with no system upset. Fast fluid separation in the High Pressure Production Traps (HPPTs) is an important strategy in order to improve process system’s performance.
High volume oil production systems typically have two HPPTs in parallel for initial water separation. Downstream of the HPPTs is the Low Pressure Production Trap (LPPT), which is mainly used for gas separation. Oil continues to the dehydrator to finish the dehydration to meet the pipeline BS&W requirement. The dehydrator is where the transformer is located for the electrostatic grid and high amounts of water separation can cause fluid levels to fluctuate and trip the transformers.
Throughout several field trial experiences, demulsifier rates can be optimized (reduced) further when it shows increased water separation at HPPT vessels. Clear water from HPPTs discharge, valves in water leg HPPTs open more (%), stable voltage grid (dehydrator/desalter), and less than 0.2% BS&W with less than 10ptb salt recorded at the export oil gives a good indication that the process is stable. Thus reduced the risk for system upset.
This paper summaries the best approach to optimize chemical rates in high volume oil production systems, analyzes qualitative and quantitative system checks to verify stable operations, and discusses potential risks involved when reaching lower limits of effective chemical rates.
Current Methods and Novel Solutions for Mitigating Lost Circulation
Authors: Ramasamy Jothibasu , Gooneratne P Chinthaka , Amanullah Md 
Published: April 2019

Abstract
This paper presents novel lost circulation materials that are being developed to address and effectively control moderate to severe lost circulation. We also present a thorough analysis of drilling methods, lost circulation scenarios and current lost mitigation strategies that have to be undertaken when drilling in severe lost circulation zones, which could also improve the probability of success of the novel lost circulation materials to cure losses. Recent development on lost mitigation materials comprising of polymers and fibers is also discussed in detail.
Practices and Understanding on the Anti-Sloughing Drilling Fluid Technology of SOilfield
Authors: Wenquan Tang , Chao Xiao , Yuzhi Xue , Tian Lu Zhang Hongbao , Chengcheng Niu , Ruiyao Wang , Qingshui He , Lingjun Kong , Zhifa Wang , Haoya Liu , Yan Li 
Published: April 2019

Abstract
In order to solve the problem of severe borehole instability while drilling in the S oilfield, technical research on drilling fluids has been carried out. Firstly, the paper analyzes the mechanism and technical difficulties of borehole instability in depth. Aiming at the reasons of borehole instability, the reasonable drilling fluid flowrate was defined by considering hydraulic erosion, drilling fluid plugging property, inhibition, etc, and the anti-sloughing drilling fluid system was optimized by way of strengthening the plugging and inhibiting properties of drilling fluid system. This technology has been applied in more than 40 wells in the S oilfield, the problem of borehole instability in the fractured formation was solved successfully, and the drilling speed was increased by 25.3%, which greatly reduced the downhole complexity and achieved remarkable application effect.
Digital Reamers to Mitigate Narrow Margin Drilling Hazards for Deepwater ERD Wells in Malaysia
Authors: Lim Ming Seong , Singh Rajpaviter , Mohd-Radzi Razif , Khor Jonathan , Wong Yau Min 
Published: April 2019

Abstract
In planning for their first TLP deep water project in Malaysia, Shell faced the unique challenge of drilling ERD wells in soft unconsolidated sands with narrow ECD margins. Prior experience suggested the benefit of managed pressure drilling & an additional casing profile with hole enlargement to be implemented for these wells. The formation is also believed to be time sensitive, and reducing the wellbore exposure time between drilling and running liner was considered a priority.
A full suite of LWD services were also planned to be run on these sections, resulting in potentially a very long rat hole as the conventional reamer can only be placed above LWD tools. An additional hole opening trip to minimize rat hole length was not desirable, which in turn leads to concerns of well bore stability due to time exposure as highlighted earlier, as well as increasing potential risk of side tracking in the soft interbedded formations. Flow rate restrictions due to the pressure drop requirements from conventional reamers, was not desirable so as to maintain ECD stability.
In order to address the needs and challenges above, contractor proposed a dual digital reamer solution, in order to ream and drill the hole sections in a single run. The digital reamers, each being powered by the LWD suite, were activated via downlinks, eliminating the lengthy time required by drop ball reamers at high angles. The ability to downlink on demand and perform selective reaming without any pressure drop restriction, had provided added benefits while drilling in narrow ECD margin. As placement of the digital reamers are flexible within the LWD tools, dual reamers were deployed in the BHA. The top reamer located above the LWD tools was activated while drilling to ensure necessary LWD data quality was obtained. A near bit digital reamer was activated post-drilling to eliminate the long drilling rat hole, resulting in minimal rat hole achieved similar to the outcomes of a dedicated trip. Eliminating the dedicated trip also greatly minimized the risk of unintentional side track.
The use of dual digital reamers enabled safe and problem-free drilling, logging, casing and cementing; allowing all of Shell’s objectives to be met in a single run, as well as significant exposure time of the wellbore, up to 3.5 days over 3 hole sections and costs savings, up to 1.2mil USD.