bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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

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.
Case Study: Quick Production Facility
Authors: Diware Amol , Khati Milind , Stoianovici Zaharia , Borase Sunil
Published: November 2015

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

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

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

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

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

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

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

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

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

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.
Heavy Crude Oil Rheology Improvement Using Naturally Extracted Surfactant
Authors: Naiya Tarun Kumar , Banerjee Shirsendu , Kumar Ravindra , Mandal Ajay
Published: November 2015

Crude oil transportation through pipelines encounters severe problems due to their high pour point and viscosity. As temperature drops below the Wax Appearance Temperature (WAT) paraffins present in the crude oil start precipitating in the inner walls of the pipelines which hinder the flow to a great extent. Sometimes the pipelines even get blocked due to high wax content of the crude oils. Various pour point depressants and surfactants have been used to deal with this problem. However they are quite expensive in terms of industrial applications. To meet these problems a new surfactant extracted from tropical Indian plant Madhuca Longifolia was used to enhance flow properties of heavy crude oil through pipelines. Experimental measurements include viscosity, yield stress, viscoelastic properties, pour point, SARA analysis, microscopic studies and FTIR studies. Experimental verification of Power Law model was justified. Crude oil surfactant mixtures tend to behave like Newtonian fluid as surfactant concentration was increased from 500 to 2000 ppm. Viscosity of crude with 2000 ppm surfactant at 30°C was almost same as that of pure crude at 50°C. Presence of surfactant significantly reduced elastic and complex moduli of heavy crude oil at 40°C. Yield stress of crude oil reduced from 0.9 to 0.017 Pa with surfactant addition at 40°C. Microscopic studies showed surfactant addition reduced size of wax crystals appreciably. FTIR studies implied that aldehydic and amine groups are responsible for high viscosity and their concentration reduced after addition of surfactant.
Mechanical characterization of composite solid rocket propellant based on hydroxy-terminated polybutadiene
Authors: Gligorijevic Nikola , Rodic Vesna , Zivkovic Sasa , Pavkovic Bojan , Nikolic Momcilo , Kozomara Stevan , Subotic Sredoje
Published: November 2015

This paper presents the procedure of uniaxial mechanical characterization of
composite solid rocket propellant based on hydroxy-terminated polybutadiene
(HTPB), whose mechanical properties strongly depend on temperature, strain
rate, natural aging and accumulated damage. A method of processing data is
presented in order to determine time-temperature shift factor and master
curves for tensile strength, ultimate strain and relaxation modulus,
depending on reduced time. Functional dependences of these features represent
an input for structural analysis of a rocket motor propellant grain. The
effects of natural aging on the mechanical properties are also considered.