bluuebunny/crossref_metadata_2025_split huggingface dataset:
Largest Liner Hanger Ever Installed Worldwide
Authors: Gomez Gonzalez Ernesto S. , Rodriguez Rico Ramon , Obi Ikenna , Bolivar Antonio 
Published: November 2019

Abstract
Some gas wells casing design call for running and cementing intermediate 18 5/8" casing string to cover weak formations (low pressure/losses) including hydrocarbon bearing formations. Some gas wells drilled in the offshore Arabian fields developed sustained Casing-Casing Annular (CCA) pressure problems, emanating from poor cement bond of the intermediate casings, especially the 18-5/8" x 24" casing annulus. This paper will examine the source of the problems, primary solutions, and the remedy for the problems.
Primary cement is the first barrier to prevent sustained CCA pressure problems; from drilling through the production lifecycle of any well. Most of the wells experienced losses while drilling or cementing the intermediate casing; the current practice is to enhance the chances of a good cement job by installing an external inflatable packer with a circulation port (DV). This device splits the cement job into two stages and enables the second stage cement return to surface. In some completed gas wells, DV and cement barrier failure were recorded, which subsequently resulted in CCA pressure development.
A solution was conceived to replace the 18-5/8" casing DV stage tool with a more reliable liner hanger (LH), in the most critical casing annulus CCA3 (18-5/8" x 24"), which has a higher risk of CCA development due to mobile hydrocarbon bearing formations covered behind the 18-5/8" casing. CCA3 pressure was reported in some wells. The shallow intervals were drilled, cased, and cemented, utilizing enhanced cementing practices and a DV tool in a 2-stage cement job.
The LH alternative offers a good solution, but no technology was available worldwide to run the 18 5/8" liner and set inside 24" 201# casing, to avoid CCA pressure in this particular annulus size. The operating company collaborated with the lLH provider to develop the world's biggest LH, with metal-to-metal seal in the hanger and rubber seal barriers in the tie-back. The LH equipment was manufactured over a period of 6 months, deployed, and successfully field tested in five wells with no CCA3 pressure reported to date. The results of this LH installation will be discussed using case histories of recently drilled wells in the field, and compare results with some previous wells. For critical high rate gas wells with associated high construction cost, any technology applied to enhance well integrity, such as installation of the 18-5/8" LH, is considered an absolute necessity by the operator.
Risk Evaluation & Sensitivity Analysis of the Exploration & Production Sharing Agreement
Authors: Balhasan Saad , Biltayib Biltayib 
Published: November 2019

Abstract
This paper has been intended at risk evaluation and to investigate the importance of the Exploration and Production Sharing Agreement (EPSA) model (equity split share, A factors, and production indices B) in terms of different capital budgeting techniques such as Net Present Value (NPV) and Internal Rate of Return (IRR). The present study has applied deterministic research approach along with stochastic research approach using Monte Carlo Simulation procedure. This technique has been adopted to determine the probable range of NPV and IRR values that are based on stochastic variable of financial terms of the EPSA model applied. The simulation output of the economic model of field development by water injection revealed that the NPV and IRR are both significantly fragile terms in case of production share. Different levels of sensitivities have been observed for factors (A) and production indices (B) in terms of NPV and IRR at fixed or variable production share. The analysis exposed that in terms of NPV and IRR, the production index B1 and B3 is relatively more sensitive than other measures. Similarly the outcomes show that in terms of NPV and IRR the production index of B4 and factor A (4) are relatively less affected than other terms. The Crystal Ball's OptQuest's was used to mitigate the financial risk by optimizing the SP's profitability indicators. The project profitability indicators NPV and IRR of the international oil company, designated the second party (SP), were optimized and improved from 16.86% to 20.00% and NPV from $175.03 million to $273.32 million, respectively.
Zohr Offshore Pipeline - Buckle Arrestor SSC Testing & Mitigation
Authors: Hussein Hesham , Elkhafif Hesham , Badran Shady 
Published: November 2019

Abstract
Zohr subsea production system (Accelerated Start Up Phase) is made by 6 wells connected via individual rigid production infield flowlines to two chained Main Subsea Structures. Gas is exported to onshore El Gamil plant through a piggable export sealine connected to the one of the two Main Subsea Structures.
In total 218 km of pipes 30inch to Zohr onshore plant El Gamil pipeline. Pipeline material and dimension combination required for the Zohr project is unique in its kind and the combination of requirements has not been produced before, with demanding mechanical and corrosion tests and a new limit for pipeline exposed to sour service.
A certain number of Buckle arrestors (107 pieces) have been used along pipeline installation. The BAA are around 12 m long and are integrated by three sections; The central sections of thickness (75.8, 66.0 and 54.0mm) are seamless forged pieces produced with ASTM A707 Grade L5 Modified steel in quenched and tempered condition with mechanical properties equivalent to API 5L L415QS / L415QO material. The pup pieces are API 5L LSAW pipes Grade L415MS / L415MO.
During Manufacturing Process Qualification Testing (MPQT) Sulphide Stress Cracking Corrosion Test (SSC) have shown some cracks of test specimens. The specimen fails and SSC cracks were found in the post test analysis, i.e., by sectioning and performing metallography at X100. These specimens were tested in NACE TM0177 type A solution with 5% NaCl and 0.5% acetic acid, saturated with 1 bar H2S at an initial pH of 2.7. Exposure duration was 720 hours and the load to be applied was 90%. No indications or defects were assessed by NDT magnetic particle inspections on all the tested specimens.
Weld overlay of buckle arrestors assemblies (BAA) with alloy N06625 (nominal thickness 3 mm) cover the full length of the central section plus the circumferential welds (that are ground flush) and extending 100 mm on each side of the girth welds into the pup pieces.
It was a challenge to overcome these defect of these pipes considering the stringent requirements in the project specifications and the tight project schedule to achieve the installation campaign without any delay on project schedule.
The Optimized Ramp-Up phase envisages an extension of the Accelerated Start Up subsea system with four (4) additional wells, a new Main Subsea Structure (MSS3), a new Subsea Distribution Unit (SDU) and a piggable export pipeline (30" OD), parallel to the 26" Accelerated Start Up Phase (ASU) export line.
Numerical Modeling and Experimental Validation of a Wellbore Cleanliness Concept During Connection Time
Authors: Ruzhnikov Alexey 
Published: November 2019

Abstract
One of the most common operations while drilling is the connection of drill pipes after every stand drilled. The main concern prior and during this operation is to ensure that annulus around the bottom hole assembly (BHA) and drill string is clean of any cuttings, when often excessive time spent to achieve it. This manuscript discusses modeling, field implementation and operational observations of changing the standard practices, what led to significant time reduction while drilling vertical, deviated and extended reach (ERD) wells.
The most common worldwide practice is to wash / ream a stand up and down prior to connection to remove any potential cuttings around BHA. Having this in mind the objective was set to minimize this time as much as possible towards full elimination. To accurately predict the cuttings lifting forces, annulus cleanliness, hook load fluctuations advanced modeling combining torque, drag and hydraulics was developed. The model considers all the key parameters such as drilling fluid density and rheology, BHA configuration, pumping rates, wellbore geometry, temperature and pressure effects, etc. and can estimate the time required to spend at the end of every stand.
A total of up to one hundred jobs were simulated and followed by the field implementation in the different sections, which were ranged by bit size (from 17-in. to 6-in.), inclination and complexity (from zero to 90 degrees, including ERD wells) as well as other affecting parameters such as losses, wellbore stability etc. The data from the initial wells were crosschecked vs available MWD/LWD data (as equivalent circulating density, annulus pressure while drilling, temperature etc.) to confirm the results of the simulations.
As a result, new connection practices were developed with minimum clean out time prior to a connection. Two examples: in the vertical wells the pre-connection time was reduced almost to zero and only two minutes drill-off now done; in deviated wells including ERD a standard approach of washing up / reaming-down a stand was replaced to 2 - 3 minutes drill-off followed by ream up and down of 10 ft only. Together with other changes it not only allowed the decrease a connection time by up to 60% without the negative incidents like stuck pipe, but also minimized impact on the bottom hole assembly (BHA) components happening due to off bottom stick / slip. This resulted in great time savings, where around 2 days can be saved for 20,000 ft wells vs previously applied practices.
The manuscript describes an engineering-based approach to connection practices which allows to shorten well construction time and decrease the well cost without additional risk.
Deployment of Lower Completions with Interventionless Inflow Control Device to Increase Operational Efficiency, Save Rig Time and Reduce Deployment Risk
Authors: Adan Iain , Boggs Reggie 
Published: November 2019

Abstract
The most common practice to deploy a lower completion with inflow control devices (ICDs) requires a washpipe assembly to facilitate deployment. Due to the nature of traditional ICDs, with open flow ports, the washpipe assembly provides a conduit to circulate fluids during the installation. However, makeup and break out of washpipe takes time, carries risk, and provides no long-term benefit to the completion or long term value to the operator.
The industry has used temporary mechanical isolation in more recent years, but these devices lack redundancy in the event of malfunction.
The objective of the hydro-mechanical ICD is to remove the requirement for washpipe, thereby reducing operational risk and rig time while eliminating HSE concerns related to drill pipe handling when deploying the lower completion. The key differentiator being additional redundancy, should manipulation be required.
An additional feature of the tool is position verification, the ICDs benefit from a passive attenae. The attenae reader can be deployed in the future to independently verify sleeve position should well optimization be required over the well lifecycle as water cut increases.
The paper reviews various techniques that have been adopted to date and concludes with presenting a hydro-mechanical solution that was successfully installed and the value derived.
Case History of a Successful Hydraulic Restimulation Pilot: The Story from Pilot Candidate Selection to Post-job Evaluation and Rollout
Authors: Janiczek Peter , Dragomir Alexandru , Stojkovski Jovan , Makar Ivan , Kolasa Bartlomiej , Paraschiv Madalin 
Published: November 2019

Abstract
This work presents the entire case history process from the recognition and identification of a potential candidate for multistage hydraulic re-stimulation. This includes operational preparations, execution, and how post-treatment results influenced the rollout of a pilot.
While the recognition of the potential candidate was a coincidence by intersecting a stimulated area from one well to a neighboring well, resulting in sustainable higher production, the study phase to identify the full field potential and candidate well identification was executed in a structured way. A primary challenge was the proper preparation of the well, while keeping the overall costs manageable.
Dedicated supply vessel has been used to accommodate stimulation equipment which was used to execute hydraulic stimulation treatments in Black Sea. Hybrid designs have been designed to carry 20/40 RCP proppant, which was pumped in four cycles. Since reservoir has been accessed by originally opened sleeves with addition of new hydrajet cuts along horizontal section the need of special degradable diverter was required to ensure good lateral coverage and proppant distribution. Together with the treatment, hydrocarbon and water sensitive tracers were pumped, allowing an allocation of flow per cycle. After shutting in the well to allow the resin coated proppant to cure, the well was cleaned out with energized fluid and returned to production
Within four hydraulic re-stimulation cycles, a total of 300 tons of proppant with approximately 2,000 m3 of fluid were pumped and successfully diverted. End of cycle ISIPs rose by more than 20 bars and back-calculation of volume of the diverter stages allowed identifying the diversion effect. During the initial flow phase, very high water cut was observed, exhibiting good cleanup of the treatment. After 2 weeks, the rate stabilized at double the pre-treatment rate and slightly above the conservative prediction.
Multistage hydraulic re-stimulation is not well utilized in Europe thus far and has not been applied offshore. In this mature field, the entire process from study to execution and post-job analysis was strongly cost driven, but resulted in the potential for six more hydraulically stimulated wells in this field.
Equivalent Circulating Density Prediction Using a Hybrid ARIMA and BP Neural Network Model
Authors: Han Chao , Guan Zhichuan , Li Jingjiao , Hu Huaigang , Xu Yuqiang 
Published: November 2019

Abstract
A hybrid methodology is presented to predict equivalent circulating density (ECD), which combines autoregressive integrated moving average (ARIMA) and back propagation neural network (BPNN) models. Research results are compared to previously published ECD prediction method that is based on theoretical calculation of hydraulic parameters.
The hybrid methodology is based on data analysis theory. It uses ARIMA model to capture the linear trends of ECD, and then the BP neural network is used to predict the nonlinear and stochastic change law of ECD. Finally BP neural network prediction results are used to correct the prediction error of ARIMA to get the ECD prediction results. With a deepwater well in the South China Sea, a simulation experiment is carried out to verify the comprehensiveness and accuracy of the method presented in this paper.
The prediction results are similar to those of the traditional hydraulics model, which considers the effect of temperature and pressure on drilling fluid density and rheological parameters. Comparisons are also provided for three classical time series prediction models, including the support vector machine, multiple linear regression and grey prediction. The root mean square error (RMSE) and the mean absolute deviation (MAD) were selected as evaluation indicators. The comparison results show that the hybrid model can reflect the variation law of ECD more accurately. Therefore, relative to the traditional methods of prediction, the hybrid methodology has the advantages of advanced modeling thought and simple operation, and it can be selected for prediction of ECD.
Because of the effects of high temperature, high pressure and uncertain factors, the accurate prediction of ECD is very difficult. This paper provides a novel idea for accurately predicting ECD by analyzing the implicit relationship of ECD series data through data mining.
Trading Risk for Reliability, Flexibility and Efficiency in NGL Plants
Authors: Patel Tushar , Tabaza Sami 
Published: November 2019

Abstract
Gas processing plants need to cope with varying and often uncertain conditions. Operators of gas processing plants in North Dakota (USA) typically face challenges with the mode of operation (ethane rejection or ethane recovery) and feed gas uncertainty (rich gas or lean gas). In terms of equipment reliability, flexibility and efficiency, these circumstances also place significant requirements on the compressor technology used. This case study will discuss the deployment of a mechanical refrigeration cycle using commercial-grade propane (95 to 98.5% propane, with the rest being heavy hydrocarbons, or HD5, or higher-grade propane). In the context of different compressor technologies available for such applications (this includes oil flooded screw, integrally geared centrifugal or inline centrifugal, the authors examine the performance characteristics of integrally geared compressor technology applied in gas processing plants.
Inherently, oil-flooded screw compressor systems require regular maintenance to ensure the availability of oil-free process gas. In turn, when seals or coalescing filters are not maintained or do not perform as expected, oil may carry over with the process gas and flows to downstream. These events require extensive cleaning and can lead to plant downtime. By comparison, integrally geared compressors and inline centrifugal compressors are 100% oil-free (no oil in compression chamber / process), providing increased reliability while requiring less maintenance. Also, integrally geared technology can be supplied with tilting pad thrust bearings which allow these propane refrigeration compressors to start at a higher suction pressure (i.e., settle out conditions on hot summer days), thus providing superior rotor stability while saving the propane because there is no need to flare the gas to reduce the system settle out pressure (Patel and Struck 2017).
With regards to the parameter of flexibility, the authors will discuss how the variable diffuser guide vanes (vDGVs) are helping to provide the process flexibility, thereby extending compressor turndown up to 50% without recycle. vDGVs can maintain a required and subsequently designed discharge pressure that gives operators flexibility with varying mole weight and head requirements. vDGVs also help with start-up during high settle-out conditions like those in refrigeration processes.
It was found that integrally geared compressors are about 10% more efficient than oil-flooded screw compressors. As each impeller has its own casing and seals, it will allow for easy accommodation of side streams. Also, integral gearing can match the impeller geometry to the required speed which results in higher compression efficiency, while dry gas seals reduce process gas leakage to improve plant reliability. Lastly, it was found that an integrally geared refrigerant compressor delivers more than USD 200 000 per year in OPEX savings, in addition to lower CAPEX of up to approximately 20% (based on the study done for a 200 MMSCFD plant).
Understanding Erosion Patterns as Potential Sites for Corrosion Proliferation
Authors: Noui-Mehidi Mohamed N. , Badeghaish Wael O. 
Published: November 2019

Abstract
In the case of coated materials, any mechanical erosion at a specified location in a flow system will lead to chemical corrosion if the fluids are in contact with the eroded zone, which presents a favorable condition for corrosion growth. In contrast, corrosion of materials can worsen by mechanical erosion when corrosion has started destroying the texture of the subject material. In the present paper, we will review erosion-corrosion aspects of metallic systems based on particle impingement mechanisms’ Finnie model and its implication of different metallic materials. The paper summarizes the effects of fine particle impingement with regard to different flow situations that can lead to mechanical erosion that will affect the chemical reliability of the metal leading to potential harmful corrosion. The paper will provide a few recommendations to avoid such situations and achieve a sound mechanical and chemical reliability of the material system in use.
Successful Use of Tubing Punch Technology in Production Restoration of a Highly Deviated Gas Well With Stuck Plug
Authors: Gadelhak Abdelrahman , Deshmukh Rohit , Sudarev Maxim , Baslaib Mohamed , Al-Badi Mohammed , Ahmed Zeeshan , Assagaf Mohamed , Al-Attar Mohamed , Al Jaberi Fawzi , Hegazy Gehad 
Published: November 2019

Abstract
The scope of the paper is to demonstrate the effectiveness of tubing punch technology for a gas well through rig-less operation to bypass flow restriction due to a stuck plug. The scope shall encompass the technology selection, challenges faces and successful deployment relative to conventional options.
In a pursuit to reduce rig time, smart solutions have been explored by the operators for effective production enhancement and reliance on multiple well interventions to save cost. The candidate onshore well in discussion is a high potential well with an average gas production of ~30 MMScf/d and condensate averaging ~4,000 STB/d. The well has been producing consistently since 1997 until 2013 where by the well was killed for maintenance activities. In 2015, an attempt to recommission the well was failed due to a stuck slick line plug. The well was attempted to flow though the equalizing ports in the plug body, however that resulted in a significant reduction of flow rate to ~ 8MMscf/d resulting in a production loss of 22 MMSCFD. Various options were contemplated in an attempt to re-instate the well to its original condition i.e. milling, workover, cutter etc., however the options were discounted considering high cost and rig requirements. Tubing punch technology/Solution was chosen in view of the cost effective rig less activity. The paper shall discuss the details of planning, inflow modelling and operational challenges for the well re-instatement to its original condition without compromising well integrity requirements. The technology implementation demonstrated a direct production gain of +/- 22 MMSCFD and +/-400 BOPD using the low cost intervention Tubing punch technology with net cost 27 K $USD