bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study: Quick Production Facility
Authors: Diware Amol , Khati Milind , Stoianovici Zaharia , Borase Sunil 
Published: November 2015

Abstract
An operator in India desired two modular, skid-mounted, plug-and-play quick production facilities (QPF) with the capacity for quick relocation and commissioning within multiple fields. This paper discusses the successful solution presented by the service company using an economic, flexible, and reliable QPF model. It also discusses challenges related to flow assurance, limited infrastructure, and compliance with the India Directorate General of Mines Safety (DGMS) challenges.
The QPF model consists of process skids, utility and storage systems, interconnected piping, data acquisition (DAQ), and a power distribution system. The well flowline is routed through an indirect water bath heater (IWBH) and three-phase separator. Oil from the separator transfers to the export oil storage tank and loading gantry. Water travels to the evaporation pond through a skimmer tank, and gas is transferred to the burn pit through a knockout drum (KOD). Liquid accumulated in the KOD is transferred to the storage tank. A closed drain maintenance vessel and alarm system is also included.
The operator used a service company to engineer, procure, install, and commission two QPFs. From a process perspective, the primary challenges encountered included flow assurance related to the presence of a variety of oils and wax with high wax appearance temperature (WAT), limited existing infrastructure in the very remote location, and compliance with the India DGMS standards. After all of the equipment/skids arrived on location, the operator requested the installation of the QPFs within a short period of time. A team consisting of local contractors and global personnel from various disciplines was assembled to meet the challenge. This team included personnel from project management, mechanical and piping, electrical and instrumentation, and construction and commissioning. The installation and commissioning of the first QPF was completed in 45 days. After applying lessons learned from the first installation, the second QPF installation was completed in only 25 days. The commissioning of the facilities in such a short time period was the result of collaborative work from both the operator and the service company.
Two modular, skid-mounted, plug-and-play QPFs with the capacity for quick relocation and commissioning within multiple fields were installed in very remote locations in India. This paper discusses challenges encountered and addressed during the operation using an economic, flexible, and reliable QPF model. Lessons learned during the first operation enabled a much faster completion of the second QPF, thus exceeding operator expectations.
Development of a Remote Oil Field Through ESP Installation: Lessons Learnt
Authors: Karurkar Shrishailam Girish , Chandra Debarpit , Gyani Omkar N 
Published: November 2015

Abstract
The ONGC operated XYZ field is the farthest oilfield from shore located in western offshore of India. Based on the remoteness and marginal nature of the field, it was developed by deploying an Early Production System and brought on production in 2006. Concurrent exploration and development activities resulted in horizontal & vertical growth of the field, nearly doubling the in-place reserves. Subsequently, the field development strategies were revised and the Early Production System was replaced with FPSO in 2013. Post FPSO installation, back pressure in the field increased leading to sub-optimal production from the self-flowing wells necessitating early installation of artificial lift.
The reservoir is multi-layered limestone in a depth span of 2100–2850m. Reservoir pressure is almost hydrostatic and temperature ranges from 120–140°C. The crude is light and highly under saturated with bubble point pressure less than 100 kg/cm2. With low production GOR (~40 v/v) and no nearby source of gas, possibility of using gas lift was eliminated. However, highly under saturated crude with favourable reservoir conditions made it an attractive proposition to install ESP as artificial lift in the field.
ESP installation campaign kicked off in May-13. The campaign suffered initial setbacks in the form of premature/frequent ESP failures resulting in production downtime. Completion of the new wells with predesigned ESP since inception led to sub-optimal production performance of some wells. The early ESP failures warranted a comprehensive review of ESP design and installation strategies followed in the field. Accordingly, accelerated mid-course corrections were made and new strategies were formulated for optimized ESP design. ESP installation methodologies were also reviewed to minimize operational hiccups. This was followed by close monitoring of ESP performance for further optimization opportunities in accordance with dynamic reservoir conditions.
The performance of ESPs designed and installed using revised methodology was in line with the expectations. With improved ESP design and installation practices, sustained production could be realized and the field witnessed turnaround in production with peak oil rate of 32000 bopd through 28 wells in Feb-15. The paper discusses lessons learnt while overcoming the challenges and procedures implemented in design, installation, operation and monitoring of ESPs in XYZ field which led to a successful endeavor to revive the field to its anticipated potential.
Quick Look Methodology for Progressive Cavity Pump Sizing and Performance Monitoring
Authors: Agrawal Nitesh , Baid Rahul , Mishra Lokranjan , Ghosh Priyam , Kushwaha Malay 
Published: November 2015

Abstract
Progressive Cavity Pumps (PCPs), if properly sized, can greatly improve a well's deliverability and run-life. As a result, PCP sizing for a large number of wells can be instrumental in a production optimization program. This paper presents a quick look methodology adopted in the Bhagyam field to better understand PCP system performance and to accurately predict pump deliverability under a wide range of downhole conditions for more than a hundred wells.
Using nodal analysis, this paper presents the procedure used to select optimum pump size and well fluid rates from well inflow and outflow performance. The paper also presents a correction factor for the effect of viscosity on pump performance and uses the corrected pump performance curves to model the expected liquid rate from a well.
The solutions obtained with the analyses have been validated against actual Bhagyam well test data and have proved to be fairly consistent. This procedure has not only been a useful tool for pump selection and performance monitoring but has also made a significant business impact in terms of incremental oil gain.The methodology quickly provides reasonably accurate solutions for pump selection and allows evaluation of real time pump parameters to optimize PCP under varying field conditions.
A Case Study - Determination of Accurate Liquid Level and its Applications in CBM Wells
Authors: Bhargava V. , Sethi A. , Singh S. , Chellani I. 
Published: November 2015

Abstract
The purpose of pumping out water from CBM well is to depressurize the coal seam to initiate desorption of hydrocarbon gases, mainly methane. Determination of accurate liquid level is required to calculate gas flow rate and well performance, to optimize pump sizes for maximum possible liquid withdrawal, for optimizing gas production, determination of pump setting depth for its optimum performance in view of NPSH and simultaneously to ensure water level to go down below the last coal seam. However, in CBM wells once critical desorption pressure is achieved, the water level monitoring gets complicated due to violent degassing and foaming. The liquid column in casing/tubing gets aerated by the gas produced from the coal seams.
This paper presents a case study done in Raniganj coal block, West Bengal, India, which is one of the major CBM block in India. The total CBM acreage of the Raniganj CBM gas field is about 500 Sq Km.
The study was done to calculate foam free liquid level with the use of mathematical formulae and portable surface acoustic liquid level measuring instrument which is quite simple and cost effective method to calculate accurate liquid level in wells that are producing considerable amount of gas, without any downhole intervention and on wells where installation of permanent gauges is not economical.
The study was done in different wells where the calculated foam free liquid level was compared with results obtained from permanently installed pressure gauges and the results were found to be quite consistent. Hence, an accurate study of liquid level can be done in CBM wells which could be further used to optimize the production without compromising on accuracy of data with minimal cost, effort and resources.
Optimizing the Fracturing Treatments by Intersecting Production Data and Fracture Diagnostics
Authors: Pandya Soham , Goyal Siddhant , Pandey Yash 
Published: November 2015

Abstract
Raniganj field in West Bengal is the largest producing coal bed methane reservoir in India, belonging to the Gondwana Super Group. Block RG (East)-CBM-2001/1 is located in the eastern-most part of Raniganj coalfield. The block was awarded to Essar Oil Limited under the CBM Round I of the Government of India in 1997. More than 1200 hydraulic fracturing jobs have been carried out since then. Fracturing treatment plans for each well in this block comprises of more than one hydraulic fracturing job since this coal-bed reservoir is made up of a number of laminated sequences of coal seams separated at variable distances. Due to a very strong heterogeneity between these seams, it is essential to understand the behavior of fracture propagation in all of them individually.
Fracture diagnostics involves analyzing the data before, during, and after a hydraulic fracture treatment to determine the shape and dimensions of both the created and propped fracture. Fracture diagnostic techniques can provide important data when entering a new area or a new formation. In most cases, however, fracture diagnostics is expensive, which limits its widespread use in industry. However, many researchers have come up with a much simpler and cost effective technique of predicting the fracture behavior based on the analysis of net pressure trend of the fracturing job. Analysis of fracturing treatment pressure behavior is an easy tool to gain some insight into the fracturing parameters and fracture propagation, and consequently, optimize the future fracturing treatments.
The ever exhaustive fracturing database of Essar Oil Limited was taken into deliberation to study the fracturing treatments carried out in different seams and an attempt is made to correlate the efficacy of these treatments based on the diagnostic tools postulated by Nolte (1979) and Conway (1985). The study is been extended to correlate the fracturing behavior of each coal seam to the production history. Consequently, suggestions are provided to optimize the future fracturing treatments in order to increase the production index of each well.
Formations like coal bed methane and other similar unconventionals are highly unpredictable when it comes to evaluating the accuracy of simulations carried out. This technique helps realize that each reservoir behaves differently and correlating different studies undertaken to study the particular reservoir will help engineers understand it better.
An Integrated Downhole Production Logging Suite for Locating Water Sources in Oil Production Wells
Authors: Bhagavatula R. , Al-Ajmi M. F. , Awad M. O. , Rajagopalan V. S. , El-Daoushy A. S. , Hassan M. O. , Shnaib F. Y. , Aslanyan I. , Prosvirkin S. , Karantharath R. 
Published: November 2015

Abstract
Understanding of fluid movement in and near the wellbore is a crucial factor for effective reservoir management including successful remedial actions and field development planning. One of the key objectives in well surveys is to detect and locate sources of fluid flows behind multiple pipe barriers. The conventional Production Logging Tool (PLT) is run to detect fluid flow and identify the type of fluid under downhole conditions, but is limited to measurements only inside the wellbore. Similarly, other diagnostic techniques, such as cement bond logging, give insight only into the cement integrity and also have limited capabilities to detect cross flows behind casing.
Recent developments in temperature and noise logging tools and advanced interpretation techniques have provided higher resolution and sensitivity, enabling the detection of previously undetectable leaks and fluid flow behind casing [1].
In the present case, a water zone has been identified in a producing formation with High Precision Temperature (HPT) logging and Spectral Noise Logging (SNL) followed by advanced numerical temperature modelling using the TermoSim software application. SNL identifies flowing zones and differentiates between rock-matrix and fracture flows, and TermoSim then numerically models heat exchange between the wellbore fluid and the surrounding rocks and reservoirs. The resulting model quantifies fluid production from each reservoir unit. Conventional production logging (PLT) locates fluid entry points in the wellbore. The integrated HPT-SNL and PLT logging suite can trace the entire water path from the reservoir into the wellbore.
This paper describes water source identification by an HPT-SNL-PLT logging suite deployed in several production wells of a Kuwait oil field. In some of the wells in this field, it has been found that water encroached into the perforations from a watered reservoir below through a channel behind the casing. In other wells, it has been found that cold water breakthrough occurred laterally from nearby water injectors. The exact identification of water sources is a crucial step in any further well remedial work to reduce or eliminate them from oil producing wells. [2]
Application of Finite Element Analysis in Subsea Pipeline Integrity Assessment
Authors: Nirgude V. V. , Venugopalan P. 
Published: November 2015

Abstract
Subsea pipelines carrying high temperature and high pressure hydrocarbon fluids are prone to failure due to global buckling. The design of such pipeline should essentially consider the effect of seabed profile (flat or uneven), types of soil on the mudline (sand or clay) and pipeline route layout. To check pipeline integrity a two step approach has been applied. In the first step, buckling susceptibility is estimated based on empirical formulation provided in research papers and code. In the next step, the buckle prone pipeline has been studied through a rigorous approach, where Finite Element Analysis tool is utilized to simulate the actual in-place scenario i.e. considering the pipeline as installed on the uneven sea bed and the effect of pipe soil interaction.
It is observed that the assumptions applied in empirical formulation result in over conservative design. Such designs have a cascading impact on the material requirement, offshore construction time and overall project cost. The FEA approach is effectively utilised to have an optimized boundary condition i.e. by allowing actual seabed modelling based on bathymetry data at close intervals, pipeline layout and a refined pipe soil contact modelling.
This paper focuses on the application of research work and code guideline for determination of susceptibility of high pressure high temperature submarine pipeline to lateral buckling and application of Finite Element Analysis (FEA) methods to assess the integrity of the pipeline system for the maximum operating condition. FE Approach can be effectively utilized to simulate the actual pipeline behaviour on seabed. It also provides the necessary design inputs for designing pipeline buckle mitigation solutions.
Flow Assurance Study in Deep Waters- A Case Study from Eastern Offshore Field, India
Authors: Jain A. K. , Sharma Kriti , Negi D. S. , Sarkar A. , Tewari D. C. 
Published: November 2015

Abstract
One of the most critical challenges facing producers today is assuring the flow of oil and gas through complex and costly long subsea tiebacks. Petroleum fluids contain paraffin wax which precipitates as a solid phase when temperature falls below wax appearance temperature (WAT). Assessment of the potential of wax deposition is therefore a standard part of most field development studies, especially in subsea where the cost of removal of deposits is much higher. Estimation of WAT is a key parameter for designing the facilities and ensuring smooth oil and gas production. Several techniques are available for WAT measurement. Most of the studies are conducted on dead oil which does not account for the effect of pressure and dissolved solution gas on wax precipitation. It is suggested to study WAT on saturated crude samples to address the issue of flow assurance.
Traditionally the studies conducted for determination of WAT were carried out on dead oil. This paper presents the results of a case study aimed to estimate the effect of pressure and dissolved gases on wax deposition on live oil in deep-water fields in Eastern offshore. The oil has high wax content along with presence of small quantity of resins and asphaltenes. It was observed that the effect of solution gas on WAT is more prononunced than the effect of pressure. This case study illustrates a more realistic approach towards determination of WAT, the effects of solution gas and pressure on the WAT of live oil and the use of this knowledge to predict the depth at which wax deposition would occur in the production tubing/line. The data generated from this study provides a more effective approach towards combating the problem of wax deposition in flowlines.
Pipeline Marine Terminals: Its Multi-Task Vessels, SPM's & Enhanced Safety Using Dynamic Positioning
Authors: Rahate Ramdas S. 
Published: November 2015

Abstract
The paper relates to Marine Support systems for offshore pipeline terminals and production facilities. The contents of the paper are in three parts as under: PART –AMid life modifications of Offshore supply vessel (OSV) to task specific vesselsPART –BEconomics of replacement of older Single Buoy Moorings (SBM"s) by new virtually maintenance free SBM"sPART – CDynamic Positioning (DP), and the human factor aspect in prevention of offshore accidents.
Marine floaters such as OSV's, SBM's and Floating Oil Storage and Off-take (FPSO) in the offshore Oil & Gas sector, are built for an economic life of 20 to 25 years. While the hull and machinery remain fit for purpose, for the entire economic life, the rapidly changing E & P technology and operational needs at times makes the vessels originally designed utility redundant.
The operational and economic benefits of mid life modifications / conversions of OSV's for gainful utility over the entire economic life are brought out in a case study of converting a general duty OSV into a task specific Offshore Terminal support Vessel. The study describes the methodology and approach for conversion / modifications and highlights how a single modified OSV can perform duties of tanker mooring assistance, floating hose handling, testing and replacement, SBM and subsea hose inspection & repair and fire fighting support. By focusing on task specific needs, the use of multiple specialized vessels can be avoided, thereby saving hiring and mobilizing expenses. It also avoids the dependence of external support which may be restricted or unavailable is some areas due political or other reasons of conflict.
Prematurely retiring still useable old technology assets by new technology enabled assets, provides cost effective and positive gains and justifies early equipment replacement. Switch over to new technology enabled SBM's provides for lower life cycle maintenance cost and virtually no operational down time for over 25 years. A case study of operational and economic benefits of replacing a still useable Turntable SBM by a Turret type SBM is presented to high light the cost effectiveness and other advantages of new technology and methods
During the early days of offshore oil field development, the OSV's were operated and maneuvered using the practical ship handling skills of the Master/ Captain. The handling skills varied from person to person and were prone to accidents due to the human factor. The use of D P vessels provided a wider safety umbrella while operating in close vicinity of Offshore Installations; however they could not be a total solution to the human factor. A case study regarding an OSV drift incident while on duty station at a Floating Production & Storage and off-take (FPSO) is presented. The incident highlights the element of human factor along with some Marine operational corrective recommendations.
Formation of Anhydrite Due to Interaction Between Water Soluble CO2(aq) and Calcite Mineral During Enhanced Oil Recovery
Authors: Chakravarty Krishna Hara , Thomsen Kaj 
Published: November 2015

Abstract
In the Low Salinity based EOR method, formation and migration of fines have proved to have profound effect on the displacement efficiency of residual oil. Salinity variations of injected brines have also been shown to affect oil recovery for WAG-CO2 processes. But the effect of fines in EOR during LSWAG-CO2 has not been previously studied. This study explores the possibility of fines formation during CO2 injection and attempts to understand its implication in EOR.
In this study we use the Extended UNIQUAC model to calculate the possibility of fines formation during CO2 injection. Detailed simulations were conducted over a temperature range of 50°C to 250°C and a pressure range of 5 bars to 500 bars. The amounts of fines formation taking place for different LSWAG-CO2 processes were correlated to the described oil recovery. It is observed that significant amounts of fines formation can take place during CO2 injection in limestone reservoirs. At reservoir conditions, a considerable fraction of the injected CO2 becomes soluble in sea water. This dissolved CO2 causes dissolution of CaCO3 from the mineral surface and releases Ca2+ ions into the pore space. Excess Ca2+ ions form anhydrite fines with the available SO42- ions. The salinity and composition of brines present in pore space shows direct correlation with the amount of fines produced during CO2 injection. With increase in temperature and pressure, the amount fines formation increased significantly.
The described oil recovery for different LSWAG injections showed a consistent correlation with the amounts of fines formation taking place in the pore space. The amount of mineral dissolution taking place was also precisely calculated using the Extended UNIQUAC model. Good correlation was also observed between calculated amounts of mineral dissolution and the observed increase in permeability. This study suggests that CO2 injection in carbonate reservoir can have two distinct effects. CO2 miscible with oil can decrease oil viscosity, thus increase oil displacement.CO2 dissolved in water causes fines formation following dissolution of CaCO3. These fines can alter sweep efficiency by blocking pore throats and also increase oil displacement through its emulsification.
Injection of CO2 leads to fines formation at most reservoir conditions. These anhydrite fines formations have been neglected in previous studies. The amount of fines formation taking place shows significant correlation to EOR obtained from LSWAG injection. The Extended UNIQUAC model can be used to precisely calculate both the amount of mineral dissolution and the amounts of fines formation taking place during CO2 injection over varied pressure and temperature conditions.