bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation and Remediation of Oil-Contaminated Sites: India-Based Case Studies
Authors: Parikh Jaydeep , Gadad Praveen 
Published: November 2015

Abstract
Oil leaks and spills often result in uncontrolled and unintended releases of contaminants in the environment. After addressing the leak and removing released contaminant, the residual oil impacts are often left in place for natural weathering and degradation. These impacts exist in many phases in the subsurface, primarily adsorbed to the soil, dissolved in groundwater and as a free product (light non-aqueous phase liquid (LNAPLs) on groundwater table. These impacts are known to contaminate soil and/or groundwater, and pose risks to human health and the environment. The degree and extent of risk depends on the release quantity, location, exposure pathways and proximity to sensitive receptors.
This presentation discusses our India-based experience and case studies including: a) investigations carried out to define the nature and extents of the contamination and quantify risks posed by the impacts, and b) various remediation technologies employed to clean up sites including bioremediation, chemical oxidation, free-product recovery system, air sparging, soil vapor extraction, and monitored natural attenuation. Monitored natural attenuation and bioremediation are typically considered the most cost-effective methods to remediate oil impacts. The presentation will also discuss the conditions under which typical remediation technologies are cost-effective and beneficial.
Use of Amine Solution as H2S Scavenger in Environmnet Friendly Manner
Authors: Ralli D. K. , Patil P. G. , Chauhan P. S. , Sahu S. K. 
Published: November 2015

Abstract
Hydrogen Sulphide is a hazardous gas on the surface as it is extremely toxic to human and even animal life, and is extremely corrosive to most metals. Its control in an environmental friendly manner has been a challenge for oil & gas industry.
At Uran Plant Hydrogen Sulphide (H2S) is received along with oil & gas through Mumbai-Uran Trunk line (MUT line) and Heera-Uran Trunk line (HUT line) from western offshore and satellite fields. Crude oil at Uran is stabilized in Crude Stabilization Unit (CSU) for removal of water and dissolved gases. The Natural gas is treated in Gas Sweetening Units (GSU) to remove acid gases viz CO2 and H2S prior to extraction of value added products. Gases liberated from Crude Stabilization Unit and Condensate Fractionation Unit, are also mixed with natural gas stream prior to gas sweetening.
An increasing trend of H2S level in oil & gas lines has been observed over a period of time. However a steep increase has been noticed recently in associated gas of HUT oil line where H2S level has increased from 400-500 ppm to 2500-3500 ppm attributed to the production of highly sour crude oil in B&S asset. As a result H2S level in CSU off gas has also increased from 600-700 ppm to the range of 1500 2000 ppm. Attempts to use spent amine solution from GSU as H2S Scavenger increased organic load and oxygen demand (COD/BOD) of the effluent water.
Lab studies at Uran revealed that sodium hypochlorite and Hydrogen Peroxide (H2O2) are suitable for reducing Chemical Oxygen Demand (COD) in treated effluent water, however H2O2 is found more effective. Accordingly a field trial run was carried out at Uran using Spent Amine and H2O2 during March 23-28, 2015.
The present work includes assessment of impact of simultaneous dosing of two chemicals i.e.
spent amine at CSU and H2O2 at ETP to allow usage of Spent Amine solution as H2S scavenger without affecting environment. Effect of H2O2 on critical parameters covered under State Pollution Control Board consent as well as other vital parameters e.g. Dissolved Oxygen and COD.
The results reveal that Spent Amine solution @ 500 ppm can be used as H2S Scavenger to reduce H2S level in CSU off gas to the range of 1000-1300 ppm from the existing level of 1500-2000 ppm. The reduction in COD of effluent water from Clarifier to Guard Pond Outlet (GPO) during Pre-dosing period was only 0.9%, and during dosing period there was about 47% reduction in COD values at GPO, which clearly indicate the level of impact of dosing H2O2 @300 ppm at inlet of Guard Pond of Effluent Treatment Plant (ETP).
Instilling Safety Culture through Engineering Design
Authors: Katke Nitinkumar , Ghatge Vishwajit , Kadam Ratish 
Published: November 2015

Abstract
This paper proposes solutions to safety issues by means of modifications to equipment engineering designs. Additionally, instilling a design-for-safety (DFS) philosophy helps further promote a safety culture. DFS is a key component of engineering. It is essential to anticipate and visualize potential safety hazards in a design at a nascent stage and solicit feedback from customers and field personnel. In most cases, making minor design changes early can greatly reduce the probability of possible hazards. Additional unexpected benefits of this process can include reductions in injuries, costs, and downtime. One example of this DFS concept is the addition of a hurdle block to avoid finger pinching when sliding pipe in pipe on a modular structure. Another example is the conceptualized design of a "mistake proof" manifold stack, which can only be stacked in ascending order of heavy to light weight. This helps avert the risk of heavy objects falling and reduces the need to lift heavyweight objects. Without using DFS, equipment might be manufactured that could present potential hazards later. However, DFS helps identify potential hazards during the design stages by performing failure mode and effects analysis (FMEA). Critical thinking is crucial. Safety features, such as additional gussets, pins, blocks, etc., that do not serve any core functionality are added to mitigate these potential fallacies and hazards. This paper provides examples to engineering solutions wherein a combination of DFS techniques and field feedback helped reduce potential hazards. Using this approach should help instill a safety culture. Enhancing safety has always been a challenge in engineering applications, and the oil and gas industry is no exception. A collaborative effort in which design changes are requested from field operations not only adds value to the design from a safety perspective but also ensures customer input is considered.
Management of Waxy Crudes for the Development of Deepwater Discoveries in Indian Offshore
Authors: B. Ravishankar , Sinha Niladri , Jayaram Rajan , Rathod P. Ramulu 
Published: November 2015

Abstract
Hydrates and waxes are the main flow assurance threats in the development of deepwater fields. Prevention of wax deposition is a key component of preferred subsea deepwater system design. This paper discusses the challenges associated during the design of a deepwater field in the Indian offshore and the means of mitigation during the entire operating envelop.
The deepwater discoveries for development lie in 400 – 800 mts of water depth, spread over 25 km with a recoverable volume of around 30 MMt of O+OE of gas and are envisaged to be tied back to a centrally located FPSO for handling and further evacuation. The fluid properties are very severe with high WAT and pour point. Limited case histories exist for deepwater fields developed with similar fluid properties. Low ambient temperature and poor fluid properties aggravate the likelihood of wax deposition and hydrate formtation. Based on the fluid characterization data for the development, issues due to wax deposition are expected. The present means of preventing flow assurance issues is through use of passive insulation, active heating or by chemically altering the thermodynamic behaviour.
Various means were analysed either alone or in combination to arrive at an effective wax management strategy to surmount the deepwater barrier and to convert resources into production. The use of dual pipe-in-pipe system with high performing insulating material, combined with cluster based development aid in fluids arriving at temperatures above WAT over major part of the profile period. During the transient conditions wax management is envisaged through flooding of the well jumpers with chemicals and displacement of flowline contents, after the no touch time. Since the fields are to be developed on a fast track basis, limited data poses challenges in design. This paper highlights the flow assurance challenges that were studied to develop suitable wax and hydrate management during operational phase while maintaining the flexibility to accommodate modifications after actual fluid property data is available.
The wax and hydrate management strategy proposed in this paper would facilitate in addressing a unique challenge of handling high WAT and pour point crudes with limited fluid data specifically in deepwater environment.
ESP Pod System With Down-hole Mechanical Isolation Enhances Pump Run-Life in Harsh Wellbore Conditions-A Case Study
Authors: Alrubaiyea J. , Alnajim A. A. , Sanyal Sayantan , Almutawa M. 
Published: November 2015

Abstract
Harsh wellbore environments reduce the run-life of an Electrical Submersible Pump (ESP), adversely affect casing integrity and require expensive ESP replacements that also subject the well to formation damage due to invasion of the kill-fluid used for well-control. Under such severe operating conditions, an ESP pod system coupled with an isolation packer and a fluid loss valve (FLV) can increase the pump run life, reduce downtime and improve well integrity. Pod system is a specially designed capsule to encase the ESP in an enclosed and sealed environment. The Isolation-packer along with the fluid loss valve (FLV) provides mechanical isolation at the sand-face during ESP replacement operations and protects the formation from the invasion of damage inducing kill fluids. During production, the system safeguards the casing from corrosive well fluids and eliminates damage to the power cable from pressure cycles; fluid enters through the bottom of the pod system and is lifted through the tubing without coming in contact with the casing above the packer. This paper describes a case history on the planning, in-house design, completion and post-installation performance of an ESP pod system implemented as a pilot study for a well in Humma field, Wafra Joint Operations –Partitioned zone. A cost effective and case specific solution was achieved by assembling the various ESP pod components together after researching the various vendors available. The objectives of higher production, improved recovery, and reduced lifting costs were achieved since installation, in the last five and a half years of ESP run-life. The pod system proved to be a customized solution for this well which was previously functioning with diminished pump performance and suffered from frequent failures that led to critical well control issues encountered during pump replacement. ESP is a preferred mode of artificial lift in the Humma field to tackle higher production rates from deep reservoirs. The post installation performance of the ESP pod system has laid the guidelines to achieve uninterrupted and commercially viable production from similar reservoirs that have sub-hydrostatic reservoir pressure and hostile downhole operating environments not conducive for a standard ESP installation and operation.
Managing Multidimensional Constraints to Drill ERD Wells in Rajasthan With High Directional Difficulty Index (DDI)
Authors: Lobo Monali , Kolay Jayabrata , Sinha Pankaj , Varghese Roy , Lang Clifford , Kant Ravi , Doodraj Sunil , Giri Suruchi , Kumar Mohit , Narayanan Shine , Ganda Sukesh 
Published: November 2015

Abstract
Drilling horizontal wells at an average true vertical depth (TVDBRT) of 850-950m to exploit the high porosity and low permeability tight reservoir of Barmer Hill (BH 1 to BH12), in the Indian state of Rajasthan required overcoming many chal-lenges. These wells were drilled from both Aishwariya and Mangala fields. The highly layered BH reservoir is primarily composed of diatomite and porcellanite.
Drilling ERD wells at such shallow depths and with land rigs that have limited capability (tubular and pump limitations) required detailed planning and flawless execution because of many inherent risks such as high torque and stand pipe pressures, poor hole cleaning, inadequate weight-on-bit transfer and stuck pipe events.
Optimum trajectory in terms of good well placement, drillability and collision risk avoidance was a priority in planning these wells in a tight network of over 350 wells.
An important concern was designing a Bottom Hole Assembly (BHA) to meet multiple requirements. It had to be planned to maximize achievable doglegs with Rotary Steerable System (RSS) to land the wells despite high uncertainty in reservoir depths.High drilling torque anticipated in 6″ hole and narrow operating window with re-spect to helical buckling were major concerns.WOB transfer while drilling ~1000 m horizontal section was critical.
ECD had to be carefully managed by a combination of good hole cleaning and the use of smaller drill pipe in order not to exceed formation fracture gradient. Good drilling practices specific to ERD wells and meticulous engineering/planning led to successful drilling of these shallow TVD ERD wells.
ASP Flood Pilot Test at Tertiary Stage in Kalol Field – A Case History
Authors: Hanotia Ankit , Singh B. P , Samanta Supriyo 
Published: November 2015

Abstract
ASP process is the current worldwide focus of research and field trial in chemical enhanced oil recovery. The process has potential to enhance tertiary oil recovery by reducing the residual oil saturation left after prolonged water flooding in depletion type of reservoir.
The present paper presents the results of the pilot test in K-XII sand of Kalol field in Ahmedabad Asset of ONGC. Kalol field is a multi-layered reservoir having 11 hydrocarbon pay zones. It is a depletion drive type reservoir and was put on production put on production in 1966. Since 1972, central line drive injection pattern was in operation for pressure maintenance and improvement in oil recovery. K-XII reservoir has produced about 30% of OIIP with the help of water injection. It is a light oil reservoir having viscosity of about 0.38–1.87 cP at reservoir temperature of 82°C and permeability varying from 20–700 mD. The acidic component is 0.10 mg of KOH/gm of oil.
After extensive laboratory and simulation studies, a small pilot consisting of 1 injector and 2 producers in line drive pattern and 1 offset well was selected for pilot testing. Single Well Chemical Tracer (SWCT) test was conducted to know the current saturation in the pilot area and was found to be 26%, which was coinciding with the laboratory determined ROS value. This indicates that pilot is almost flooded and saturation is close to residual oil. Injection commenced with injection of 20% of Ammonium Thiocyanate tracer in Oct. 2013 to monitor the front movement. ASP injection started in Feb. 2014.
ASP solution consisting of 0.30 Pore Volume (Alkali −3.0 Wt.%, Surfactant-2000 ppm, Polymer – 300 ppm) has been injected and injection of 0.20 PV of mobility buffer (300 ppm) started in May 2015, which will be followed by chase water. The results of last 15 months of the pilot are encouraging and incremental oil produced is about 3876 m3 (June 2015), which is about 68% of the envisaged oil through simulation. Average Water cut reduction is about 10–15 %, however, significant water cut reduction was observed in one offset well, from 87% to 40 %. The effectiveness of the pilot is also reflected in the production of oil in form of emulsion which was generated in-situ by reaction of oil with alkali and surfactant.
This paper discusses the details of the laboratory studies, simulation study, pilot design, injection schedule, monitoring of injection fluid quality, production performance and lessons learnt. The success of this pilot leads to expansion and application of this CEOR process to other major reservoirs of Kalol field.
Seamless and Welded Tubes for SSSV Control Line Application – Evaluation on Superduplex Grade
Authors: He Wenle , Soerowidjojo Kukuh , Jain Karan 
Published: November 2015

Abstract
Today's welding technology has been developed which enables to minimize the negative effects of the welding. Further processes on the longitudinally seam welded tubing like sink or plug drawing will improve the geometry of the tube in both outer and inner diameter to smoothen the weld bead and increase the wall thickness and outer diameter tolerances of the tube. Annealing process on the entire welded tubing eliminates residual stress from welding and cold forming. However, the weld defects are difficult to be entirely removed by these processes and therefore the seam welded tubes carry more risks of failure to be used as sub surface safety valve (SSSV) control lines and chemical injection lines.
The selected seam welded tubes and seamless tubes of Superduplex 2507 (UNS S32750) stainless steels in similar dimensions and of similar chemical compositions have been studied by using CPT determination with ASTM G150 method, scanning electron microscope (SEM) for microstructure and surface analysis. This study shows that seam welded tubes have similar hardness compared to the seamless tubes. However the weld defects, such as undercut, micro-cracks and oxides along the fusion line, could be responsible for the reduced corrosion properties of the tube.
This study signifies that the seamless tubing is a better option as SSSV control line to maintain well integrity than seam welded tube.
Integrated Supply Chain Outsourcing - Expanding the Role of Third Party Logistics in the Upstream Industry
Authors: Singh Gurdeep , Tripathi Anant , Srivastava Anupriya , Iyer Mahesh 
Published: November 2015

Abstract
Supply chain in upstream oil & gas is complex and riddled with unique challenges. An E&P company transports a variety of materials ranging from an oil rig to a fastener. Large volume of import material is transported across international waters and then hauled to work sites deploying multi-modal transportation. All supply chain operations have to follow strict compliance to various regulatory provisions, law of the land and high HSE standards. In addition the industry demands flexibility and assurance. - a rig standby as a result of material unavailability can cost upto a million dollars per day. Cyclical nature of the oil business requires an efficient supply chain. During the crests the focus is on extracting oil as much and as fast as possible whereas during the troughs cost effectiveness is key.
In mature and developed Oil & Gas upstream markets such as USA, North Sea, Middle East the scale of activity has spawned consolidation in supply chains. Local material suppliers have developed significant infrastructure that is shared across different operators in a region. Thus operators partner with material suppliers to maximize efficiency and cost effectiveness across their supply chain. Unlike mature markets, developing oil & gas markets like India reel through fragmented supply chain operations. In general, companies internalize supply chain activities and deploy logistics companies tactically leading to disjointed processes and lack of material visibility.
Cairn India (Company) operates the largest onshore producing block in India. Like other E&P companies in the region Cairn handles its supply chain in-house. Due to several challenges in the existing model a strong need to revamp the system was felt. Cairn has taken the initiative to develop a vendor base in India to emulate the structured and integrated supply chain prevalent in mature markets. The contract structure is innovative to enable scale, performance linked compensation and aligns the goal of the service provider with that of the operator. This strategic partnership is expected to fetch multi-fold benefits for the operator including: ○Efficient supply chain management that is scalable as per business requirements○Improved inventory planning and optimization through material visibility and tracking○Enhanced business performance through robust Service Level Agreements○Reduced transactional effort and enhanced focus on core business activities
During the development of the model, prospective partners were engaged at multiple levels to validate the practicality of implementation. The paper discusses the model in more detail along with key risks in terms of its implementation, partner performance and execution.
This contracting approach is a significant leap towards increasing the efficiency and effectiveness of inbound supply chain in the undeveloped geographies. The success of this model can be easily replicated and the benefits could be reaped by industry at large.
Production Optimisation in Mature Fields
Authors: Tiwari Amitosh , Sharma Neel Mani , Manickavasagam Chandran , Fartiyal Prashant 
Published: November 2015

Abstract
Reservoir uncertainties, increasing water cut, vertical lift performance, well integrity issue along with decline in production are some of the typical challenges of a mature asset. These coupled with ageing facilities and lower production efficiencies are key issues that an operator faces while operating any mature asset. Production decline from a mature field cannot be fully arrested. However, it can be reasonably controlled by using real-time optimisation techniques.
This paper deliberates on how BG India has been able to address these issues successfully while operating mature assets in Mumbai offshore region. This paper presents how real-time production data, performance monitoring and application of innovative techniques can help in adding extra barrels to production. In the past few years, oil industry has been moving towards Real-Time Optimisation (RTO). However, to achieve optimal benefit from RTO, a new implementation approach-based on People Process Technology (PPT) framework has also been proposed in this paper.
This paper recommends innovative practices like integrating non-technical disciplines, for e.g. Logistics, Planning, Contracts and Procurement etc into core production enhancement team. It also presents techniques to setup required processes to complement the traditional way of production opportunity and loss management. Furthermore, an outline has been presented on how to select the suitable technologies during the state-of-the-art Real-Time Optimisation Centre (RTOC) set up for any Oil and Gas asset.
Several case studies have also been included in the paper to highlight the benefits from a RTOC based on PPT framework to manage the typical challenges of a mature asset. Using this approach, BG India has been able to reduce decline in production while achieving high production efficiency of more than 90 percent in the last three years for its fields in Mumbai offshore region. Going forward, more and more assets worldwide are likely to enter into the mature stage of lifecycle. Methods suggested in this paper provide a unique approach to implement a strategy to shift production management culture from reactive to proactive domain.