bluuebunny/crossref_metadata_2025_split huggingface dataset:
Electrical Interference-Emerging Threat to Pipeline
Authors: Gangula Venkateshwar reddy , Bera Kamlesh 
Published: April 2019

Abstract
This paper covers the problem related to AC interferences on East West Gas Pipeline (EWPL) and the mitigation measures taken for reducing / eliminating the same.
AC interference was observed in Hyderabad region due to AC EHV Transmission lines crossing EWPL, three phase transformers and Single wire earth return (SWER) single phase transformers in the vicinity of pipeline. AC PSP voltage up to 80 Volts were observed on pipeline during night hours for which various mitigation measures were taken to bring down in acceptable range.
Similarly, there is possibility of high voltage surge at station facilities along the pipeline route due to vicinity of multiple structures, long pipeline length and having multiple conducting structures at MLV stations comprising of RTD’s, die-electric isolators, impulse Tubing for power gas and associated power gas and control equipment. Surge travel to such system can result in equipment failures. Various pro-active measures to mitigate such instances were adopted on pipeline system and are implemented successfully.
This paper illustrates the extent of the risk of corrosion, surge impact due to AC interference / surge and gives insight to various methods deployed for minimizing these risks in simple and most economical way. It also highlights the need for collaboration and operational coordination between the pipeline operators and state electricity boards to resolve such issues mutually & in most effective manner.
A Novel Cationic Polymer System That Improves Acid Diversion in Heterogeneous Carbonate Reservoirs
Authors: Sarmah Abhishek , Farid Ibrahim Ahmed , Nasr-El-Din Hisham , Jackson Jennifer 
Published: April 2019

Abstract
In-situ gelled acids have been used for acid diversion in heterogeneous carbonate reservoirs for more than two decades. Most of the gelled systems are based on an anionic polymer that has a cleaning problem after the acid treatments that leads to formation damage. This work evaluates a new cationic-polymer acid system with the self-breaking ability for the application as an acid divergent in carbonate reservoirs.
Experimental studies have been conducted to examine the rheological properties of the polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1,000 s-1). The impact of salinity and temperature (80 to 250°F) on the rheological properties of the acid system was also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G’) and viscous modulus (G") of the system. Single coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The impact of permeability contrast on the process of diversion was investigated by conducting dual coreflood experiments on Indiana limestone cores which had a permeability contrast of 1.5-20. CT scans were conducted to study the propagation of wormhole post acid injection for both single and dual corefloods.
The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining with temperature. For 5 wt% HCl and 20 gpt polymer content at 10 s-1, the viscosity decreased from 230 to 40 cp with temperature increasing from 88 to 250°F. Acid spending tests demonstrated that the acid generated a gel with a significant improvement in viscosity to 260 cp (at 250°F and 10 s-1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher permeability zone. The viscosity of gel continued to increase until it broke down to 69 cp (at 250°F and 10 s-1) at a pH of 4.8, which provides a self-breaking system and better cleaning. Coreflood studies indicated that the wormhole and the diversion process is dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F.
The strong elastic nature of the gel (G’= 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This novel acid-polymer system has significant promise for usage in acid diversion to improve stimulation of carbonate reservoirs.
Effect of Fluid Expansion and Clay Diagenesis on Shale Reservoirs
Authors: Dutta Jayanta , Sahoo Ajit Kumar , Srivastava Mukul , Vishal Vikram 
Published: April 2019

Abstract
Shale plays are anisotropic in terms of their reservoir quality which gets reflected in their productivity. Reservoir qualities like organic richness, thermal maturity, hydrocarbon saturation, the volume of clay, brittleness and pressure affect the productivity of the shale plays. In general, the volume of clay has a negative relationship whereas other parameters listed above have a positive relationship with production. In our study area, we found the deepest wells despite having better rock quality; do not perform like nearby shallower wells. The objective of this study is to understand the not so obvious reason behind underperformance of these deepest wells.
Since the wells are located at a deeper depth and the reservoir temperature is high (90 to 135°C), so we studied the area from clay diagenesis and fluid expansion perspective. We have reviewed the imprints of clay diagenesis with the help of XRD data and core integrated multi min processed wireline logs. We observed an increasing trend of illite, chlorite towards the deeper part of the reservoir along with a decreasing trend of smectite in the same direction which indicates a higher degree of clay diagenesis. Fluid expansion study is carried out with the help of total organic carbon and hydrocarbon saturation. This study indicated a higher degree of fluid expansion (TOC to hydrocarbon generation) in the deepest part.
Subsequently, 1D pore pressure, stress and rock mechanical modeling is carried out to evaluate the effect of a higher degree of diagenesis and fluid expansion on geomechanical parameters (pore pressure, stress and brittleness). 1D modeling reveals that the deeper wells have abnormal pressure, stress and low brittleness, which is primarily due to extra pressure contribution from fluid expansion and clay diagenesis apart from the compaction disequilibrium process. This abnormal stress and reduction in brittlness likely to have created challenges for the applied hydrofrac job in the deepest part resulting to narrow frac geometry. Comparison of hydraulic fracture modeling between a shallow and the deepest wells reveal that the hydraulic fracture geometry in the deepest well is narrower than the shallower well. So we came to the conclusion that the deepest wells are underperforming than the shallower wells despite of their better rock quality due to ineffective fracturing and comparatively narrower fracture geometry.
The impact of clay diagenesis and fluid expansion in shale productivity has not been studied widely. Though many authors have extensively studied the impact of clay diagenesis on permeability and pore pressure, the integration of shale well production is rarely attempted. This work will help the operators to better analyze and understand their shale reservoir from clay diagenesis and fluid expansion point of view before planning the hydrofrac jobs.
Novel Techniques for the Evaluation of Hydrogen Sulfide Scavenger Performance and By-Product Stability
Authors: Patel Niley , Rafferty Andrew , Stewart-Liddon Christine , Hammonds Paul , Graham Gordon M. , Maskell Phillip , Frigo Dario M. 
Published: April 2019

Abstract
A technique has been developed to allow for the comparison of scavenging rates and scavenging capacity of different hydrogen sulphide scavengers by continuously measuring the hydrogen sulphide concentration in the gas phase of a multiphase system. In addition, the stability of the scavenger reaction products has also been investigated.
The methodology to assess the performance of the hydrogen sulphide scavenger is described. The scavenging rates of the hydrogen sulphide scavenger are compared by the contact time required to reduce the initial hydrogen sulphide concentration to a pre-determined value. In addition, the scavenging capacity of the scavengers can be calculated by recording the gaseous hydrogen sulphide concentration once the reaction has been allowed to run to completion. Finally, the stability of the scavengers and their reaction products, including carbon disulphide, are determined by treating a solution of the scavenger with excess hydrogen sulphide.
It is known that hydrogen sulphide scavengers have the potential to form reaction products that can foul the refining process. More recently, it has been identified that carbon disulphide may be produced during the scavenging reaction of some commonly used triazine based chemistries, driving a desire to identify alternative products. These works describe a new method which is capable of differentiating between the hydrogen sulfide scavenging performance of different chemistries. It also allowed for the scavengers to be differentiated with respect to the formation of both solid and oil soluble by-products, with the presence / increase in carbon disulphide analysed by gas chromatography. By doing this, the method allows for improved scavenger selection on the basis of performance, compatibility and cost.
This work presents a novel method for the assessment of relative reaction rates and scavenging capacity of hydrogen sulphide scavengers. In doing so, it allows the evaluation of cost performance and suitability of different treatments and scavenger chemistries to be evaluated. Additionally, the likelihood of a scavenger chemistry fouling the refining process due to the production of reaction by-products can be investigated.
Addressing Issue of Hydrate Inhibition during Start-Up of a Deepwater Field - A Case Study
Authors: Hazarika Simanta , Rathod P. Ramulu , Burla Ravishankar , Das Gour Chandra , Rao Bkvrl , Deuri Budhin 
Published: April 2019

Abstract
Subsea flow lines in deep water are typically exposed to high pressure and low temperature conditions which can create problems due to formation of gas hydrate. The gas hydrate formed can plug the flow lines causing not only loss of production, but may also create severe safety and environmental hazard. Moreover, dissociation of these plugs may take weeks or even months. Assessment of the hydrate formation potential during both steady is therefore an essential part of field development studies.
The paper presents a case study of a gas field located in KG basin of India which was brought on production in 2018. The objective of the study was to assist the on-site team on issues related to hydrate inhibition during ongoing initial start-up operation and assess the arrival time of rich MEG in the onshore plant in view of turn down flow conditions during commissioning.
The study also demonstrates how the transient simulations helped to monitor progress, identify and respond quickly to address the challenges during initial start-up operation of the deepwater gas field in Indian east coast. It emphasizes the need for accurate estimation of rich MEG arrival time and the minimum required gas flow rate from the subsea wells to ensure timely return of rich MEG to the onshore plant in order to avoid disruption in hydrate inhibition in the subsea system.
Evaluation of Zwitterionic Surfactant for Applicability in Enhanced Oil Recovery
Authors: Kumar Amit , Mandal Ajay 
Published: April 2019

Abstract
The objectives of the present study are to evaluate a zwitterionic surfactant for applicability in EOR. The surfactant was tested in terms of its salt tolerance, thermal stability, interfacial reduction capability, wettability alteration and resistance to adsorption. The effect of salinity and alkalinity was also tested on the above stated physico-chemical properties of the surfactant.
The salt tolerance of the surfactant was tested by testing for precipitation of surfactant solution with increasing salinity at 30 °C and 80 °C. The thermal stability of the surfactant was tested by TGA testing. The interfacial tension of the crude oil and surfactant solution with varying surfactant concentration, salinity and alkalinity was tested by spinning drop technique. The wettability alteration by surfactant solution was tested by measuring contact angle on an oil wet sample. The adsorption study was done by measuring the concentration of surfactant after its solution was exposed to adsorption on crushed rock sample.
The surfactant had salt tolerance of 20% salinity. The surfactant was found stable to 130 °C as per TGA curve. The interfacial tension (IFT) was reduced to ultralow value by surfactant solution for concentration at and above its critical micelle concentration. The presence of salt had minimal effect on the IFT reduction capability of the surfactant solution. Presence of alkali had synergetic effect on IFT reduction. The wettability of the oil wet sample was altered to preferentially water wet by surfactant. The loss of surfactant due to adsorption was found to be within recommenced range for applicability in EOR. These excellent physico-chemical properties of the zwitterionic surfactant suggest that it can be used in the mature oil fields for recovery of trapped oil.
Slot Recovery & Sidetracking Using Dual Casing-Exit Whipstock Technology in a Single Trip
Authors: Gupta Arpit , Thomas Emil , Tomar Gaurav , Rawat Ishita , Prakash Aditya , Golwalkar Anirudh , Vermani Sanjeev 
Published: April 2019

Abstract
In offshore platforms, with high well density, slot recovery technique is an efficient way to target new / un-swept avenues to boost the production levels in a mature field. This leads to utilization of an appreciable length of parent bore which is an advantage to the operators globally in terms of surface facility retention and associated rig time saved. This paper discusses an actual case-study wherein dual casing exit was achieved in an offshore platform well resulting in significant time and cost savings.
For the subject well the subsurface targets were quite far from the mother-bore, resulting in a plan to side-track the well at a shallow depth where double casing existed, i.e. 9-5/8″ × 13-3/8″. The options available were pilot milling and dual exit using whipstock. Unlike multi-casing exits, pilot milling is a time consuming method which requires multiple trips and involves large volume of metal swarf handling at surface. The CBL-VDL verified the presence of cement outside 9 5/8″ casing that further supported the case of dual casing exit operation. Consequently, associated risks were discussed and plans to mitigate the same were put in place.
Single-trip 8-1/2″ whipstock-milling system was used to cut a window suitable for running drilling BHAs, liner, and completion equipment. The 9-5/8″ × 13-3/8″ annulus was monitored during milling and FIT test to check for any pressure communications. For well control scenario, arrangements were made for connecting the annulus to the choke manifold to ensure a closed system and thereby have provision of circulating through choke in case of gas migration in the 9-5/8″ × 13-3/8″ annulus. The window milling operation was done using sea water & intermittent Hi-vis sweeps. The window was milled successfully in a "single trip", thereby saving considerable rig time. No excess drag or held-up was observed and gauge loss on mills when pulled out of the hole was negligible. Well integrity was intact with no pressure communication in the annulus. The job was a successful one that led to finishing the well within the planned time and thereby, led to timely release of the jack up rig before the onset of adverse weather conditions.
Multi-casing exit technology in two or three casing strings opens the multi-level advantages to well intervention techniques especially in situations where the wells are old with limited access due to presence of fish or other restrictions that makes the deeper section of the well non-usable. Such sections can be avoided by sidetracking at a shallow depth and also provides an opportunity to access targets that are quite far from the original mother-bore.
Prediction of Lost Circulation Prior to Drilling for Induced Fractures Formations Using Artificial Neural Networks
Authors: Alkinani Husam H. , Al-Hameedi Abo Taleb , Dunn-Norman Shari , Alkhamis Mohammed M. , Mutar Rusul A. 
Published: April 2019

Abstract
Lost circulation is a complicated problem to be predicted with conventional statistical tools. As the drilling environment is getting more complicated nowadays, more advanced techniques such as artificial neural networks (ANNs) are required to help to estimate mud losses prior to drilling. The aim of this work is to estimate mud losses for induced fractures formations prior to drilling to assist the drilling personnel in preparing remedies for this problem prior to entering the losses zone. Once the severity of losses is known, the key drilling parameters can be adjusted to avoid or at least mitigate losses as a proactive approach.
Lost circulation data were extracted from over 1500 wells drilled worldwide. The data were divided into three sets; training, validation, and testing datasets. 60% of the data are used for training, 20% for validation, and 20% for testing. Any ANN consists of the following layers, the input layer, hidden layer(s), and the output layer. A determination of the optimum number of hidden layers and the number of neurons in each hidden layer is required to have the best estimation, this is done using the mean square of error (MSE). A supervised ANNs was created for induced fractures formations. A decision was made to have one hidden layer in the network with ten neurons in the hidden layer. Since there are many training algorithms to choose from, it was necessary to choose the best algorithm for this specific data set. Ten different training algorithms were tested, the Levenberg-Marquardt (LM) algorithm was chosen since it gave the lowest MSE and it had the highest R-squared. The final results showed that the supervised ANN has the ability to predict lost circulation with an overall R-squared of 0.925 for induced fractures formations. This is a very good estimation that will help the drilling personnel prepare remedies before entering the losses zone as well as adjusting the key drilling parameters to avoid or at least mitigate losses as a proactive approach. This ANN can be used globally for any induced fractures formations that are suffering from the lost circulation problem to estimate mud losses.
As the demand for energy increases, the drilling process is becoming more challenging. Thus, more advanced tools such as ANNs are required to better tackle these problems. The ANN built in this paper can be adapted to commercial software that predicts lost circulation for any induced fractures formations globally.
Digital Technology Optimizes Unconventional Well Planning by Integrating Cross-Domain Expertise
Authors: Akpenyi Chukwuka , Yuan Zhaoguang , Carson Dan , Hebert Zachary 
Published: April 2019

Abstract
Traditionally, petroleum exploration and development teams have utilized workflows and software which require single instance installation and cater to domain-specific needs. Design results from one domain would require incorporation into applications of other associated domains to deliver team-wide engineering. This is often time consuming, requiring multiple review meetings and extra administrative effort for the drilling engineer.
To add to the complexity, whenever iterations or sensitivity evaluations are needed across the entire plan, there is often no simple platform within which all the required processes can be managed, requiring engineering evaluations to be executed across multiple software. An example is hydraulics which is required for mud design, bottom hole assembly (BHA) and bit design, hole cleaning and borehole stability aspects of drilling. Although all these engineering considerations evaluate the same fluid properties, they typically sit on separate engines and are only integrated by criteria and thresholds in the final plan and not through concurrent engineering design.
This paper presents a new cloud deployed well construction planning solution, that aims to resolve these historical challenges by enabling multiple processes to be connected and executed from a common contextual dataset in a single system. For example, the hydraulics design is coherent across all design tasks which increases planning efficiency and plan quality. The entire solution also integrates across domains, from geology and geomechanics to drilling engineering and service company planning. This coupled with project orchestration, team collaboration and data management provide further productivity gains and cost savings for the entire team.
This paper summarizes the digital well construction planning solution and provides case study examples of how cross domain experts plan concurrently in a single common system. This approach allows a teamwide focus on planning better wells faster in a single engineering solution. Case studies show how the well planning team was able to improve cross-discipline collaboration between engineering and geoscience as well as interactions with service companies. Overall, the well planning time was reduced significantly, and the reliability of the well design was ensured through the engineering validation of each task. The integrated digital well planning solution proved to be a more cost-effective solution for well planning and ensured the high-quality delivery of drilling programs.
Hypervolume-Based Multiobjective Optimization for Gas Lift Systems
Authors: Deng Lichi , Olalotiti-Lawal Feyisayo , Davani Ehsan , Castiñeira David 
Published: April 2019

Abstract
Gas lift is one of the most widely used artificial lift methods, and the use of nodal analysis to generate the gas lift performance curve is well established. However, the optimal gas injection rate is often selected as the point with maximum liquid production, which neglects the cost of incremental injection gas volume. This paper investigates the determination of the optimal operational point using a multiobjective optimization technique by considering the trade-off between gas consumption and oil production. The indicator-based evolutionary algorithm transforms the multiobjective problem into a single objective one using the hypervolume metric computed in the objective space. For the gas lift problem, which is a bi-objective problem aimed at maximizing oil production while minimizing gas injection rate, the hypervolume metrics are identically equivalent to geometric hyperareas under the trade-off curve. The optimization is only applied to the monotonically increasing portion of the gas lift performance curve; thus, all trivial sub-optimal conditions are excluded. The optimal operational point of gas injection rate is determined by finding the maximum rectangular hyperarea under the performance curve. The proper determination of the optimal injection gas rate could not only improve the efficiency of the gas lift itself, but also reduce the burden on the maintenance of surface facilities. The method is also applied to the multi-well scenario where a novel multi-well gas lift performance curve is generated using multiobjective Genetic Algorithm, which could help determine the optimal gas allocation/distribution scenario. The described process is incorporated in an integrated workflow which further leads to fast delivery of analysis/results that enable production engineers to make smarter decisions faster in a repeatable way.