bluuebunny/crossref_metadata_2025_split huggingface dataset:
Isolation and Characterization of Biopolymer Producing Omani Aureobasidium Pullulans Strains and Its Potential Applications in Microbial Enhanced Oil Recovery
Authors: Elshafie A. , Joshi S. J. , Al-Wahaibi Y. M. , Al-Bahry S. N. , Al-Bemani A. S. , Al-Hashmi A. , Al-Mandhari M. S. 
Published: April 2017

Abstract
Worldwide partially hydrolyzed polyacrylamides (HPAM) are preferentially used for polymer-based enhanced oil recovery (EOR) processes, due to cost-competiveness. However in recent past several reports suggested that there are certain issues associated with treatment of produced water – post HPAM applications such as, oil-water separation due to emulsions and toxicity associated with degradation products of HPAM, such as acrylamides. Biopolymers are biodegradable and environmental friendly alternative to chemical polymers used for EOR applications. In present work we studied the biopolymer-pullulan production by fungal isolates of Aureobasidium pullulans, isolated from Oman, partial structural characterization and potential applications in Microbial Enhanced Oil Recovery (MEOR).
Different production media containing carbohydrate based carbon sources were screened for better biopolymer production. During the course of experiments we studied fungal growth profile and biopolymer production under different conditions, and rheological properties of biopolymer, chemical characterization and application of biopolymer in enhancing oil recovery using Berea sandstone cores.
The observed growth and production temperature was up to 35 °C and optimum was at 30 °C for Omani A. pullulans isolates. The better growth was observed under shaking conditions. A. pullulans strains are reported to produce a type of biopolymer – pullulan. Thus samples were analyzed from Omani isolates for biopolymer production using rheological studies for any changes in viscosities with respect to time. The cell-free broth showed increase in viscosity from 1-4 cP of the abiotic control production media (without biopolymer) to 28-59.9 cP of the cell free broth at 25 °C. The initial yield of crude extracted biopolymer was ≥12.68 g/L. The biopolymer was extracted in crude form and partially identified by Fourier transform infrared spectroscopy (FTIR), which showed similarity in chemical structure with reference standard pullulan from Sigma, USA. When this biopolymer-pullulan was used for MEOR studies using Berea core-plugs in core-flooding experiments, it recovered additional 9.4% oil over residual oil saturation (Sor).
Frac Characterization of Indian Cambay Shale through Hydraulic Fracturing in First Cambay Basin Shale Well
Authors: Jha Ajay Kumar , Mahawar Dheeraj , Kumar Rajesh , Das Santanu , Rajendra KWS 
Published: April 2017

Abstract
Traversing the tight unconventional shale reservoirs is an Engineering challenge. The paradigm shift from conventional to unconventional reservoir resource exploitation was endured upon with Well CS#A, the shale gas/oil Well in Cambay Basin. The domain expertise in conventional reservoirs was manoeuvred, redesigned and translated into successful Hydraulic fracturing execution in CS#A. Frac data was further analysed and assimilated to draw the characteristic frac behaviour of Indian Cambay Shale. Cambay shale is the main source rock, thermally well matured and falls within the oil window but have never been explored for production before.
Triaxial Compressive Strength Test with Acoustic Velocities and various lab tests were performed to determine shale rock mechanics and a suite of petrophysical properties. CBL-VDL-GR-CCL logs ensured good cementation. Specialised 3D model Simulator was used with the best input parameters to conceive the best and specific design for Cambay shale. Initially, slick water was used for Step Rate Test (SRT). MF analysis carried out to ascertain key informations and subsequently, changes were incorporated in Main frac design simulation. The frac fluid was exclusively designed and optimised through tests in Laboratories to give best results and to check the compatibility with Cambay Shale & post job flow back recovery. Closure analysis was done by the most reliable G Function time BHP analysis and the same was verified with Square root time plot. The real time pressure graph trend showed net pressure increase during proppant packing suggesting better frac behaviour and fracturing prospects. Post Job, the real time Net-Pressure match facilitated simulation of real time data to know the actual frac dimesions created after job, the frac profile, validate the permeability and stress, check the conductivity gain etc.
The extensive and exhaustive research, planning and execution of hydraulic fracturing job in CS#A proved the producibility and potentiality of Cambay Shale as the Well has produced Oil. The Geological data, the log data combined with the experience gained and data inferred by exploitation of this Cambay shale gas/oil Well "CS#A" through Hydraulic fracturing will be a boon for the E&P of Unconventional Shale in India.
Use of Side Wall Core as a Tool for In-Situ Combustion Monitoring
Authors: Pareek Ramesh C. , Velmurugan Guru Prasanna , Goyal Mayank 
Published: April 2017

Abstract

Objective / Scope
This paper deals with the use of Side Wall Cores as a tool to monitor In-Situ Combustion (ISC) process performance in Balol field of ONGC where ISC process is being applied on commercial scale since 1997.

Methods, Procedures, Process
Balol field is about 13 km in length from south to north & 1 km wide. It is an unconsolidated sandstone reservoir having pay thickness is in the range of 6 to 20 m and oil viscosity in the range of 150 to 1000 cP at reservoir conditions and increasing from south to north. The process is successful in enhancing the oil recovery from envisaged 13 % of OIIP to 19 % of OIIP. However, the performance of the process was different in different sector depending on the pay thickness & the oil viscosities. The oil recovery is 54 % of OIIP in southern part of the field where thickness and oil viscosity are moderate as compared to the oil recovery of 5 % of OIIP in northern part where thickness and viscosity are high. Various attempts viz. reduction in spacing between injectors and producers through infill drilling and drilling of horizontal wells were made to improve the ISC performance in this sector but there was not much success.
To understand the reasons for poor process performance in northern part of the field conventional coring along with Side Wall Core (SWC) were carried out in a replacement air injector which was just 13 m away from the old air injector. The results of conventional core and side wall cores were correlated. As the conventional coring is cost intensive and involves complication, only SWC was carried out in another replacement air injector falling in southern part of the field which is 80 m away from the old air injector.

Results, Observations, Conclusions
The conventional core & SWC of the well from northern part indicated that in thick pays the burning is taking place only in top few meters of the pay and major part of the pay is unaffected by the process. The SWC analysis in the southern part well having moderate pay thickness indicated that the entire pay participated in the burning. This indicated very good vertical sweep and oil displacement.

Novel/Additive Information
Air injection design is based upon the oil characteristics, fuel deposition, pay thickness, porosity etc. The core analysis indicated that in thin reservoirs vertical sweep efficiency is very high as compared to thick reservoirs. In thick reservoirs burning occurs in top few meters and any increase in air injection rate result into the early flue gas breakthrough and subsequent loss in oil production. The core data & the process performance of the various sectors of Balol field confirms that ISC process is more effective in terms of volumetric sweep and oil recovery in moderately thin reservoirs as compared to thick reservoirs and application of the process in thick reservoirs need relook while designing of the process.
Novel Idea for Optimization of a Progressive Cavity Pump PCP System at Different Stages of Coal Bed Methane CBM Well Life
Authors: Vora Jinen , Singh Rahul , Saxena Shivam 
Published: April 2017

Abstract
This paper provides the design and operating considerations for Progressive Cavity Pumping (PCP) systems in Coal Bed Methane (CBM) wells based on field experience and illustrates their optimization with case studies of C-Fer software simulation and field trial. The challenge is to effectively lift water throughout the CBM well life with the same PCP system while accommodating pressure head increments and flow rate decrements with time. This paper presents a novel idea to optimize PCP system at different stages of CBM well life with minimal cost implications to the company.
The major inputs for artificial lift design are seam depth and well productivity, while PCP head and flow rate, down-hole string sizing and motor sizing are the required outputs. To take a case study of PCP system optimization, we have Well – A, where the bottom perforation is at 600 m and the water production is expected to start with a peak of 150 m3/day at 100 m water level and reach 100 m3/day at 600 m water level in about 10 months. The authors chose a system with flow capacity of 76 CMD at 100 RPM and lift capacity greater than 800 m. Tubing size of 2.875″ is chosen and sucker rod size of 1″ is chosen. The surface motor of 22 kW is selected based on the maximum power required by the PCP system at the maximum lift condition. The process of selection is depicted clearly in this paper.
Although, the PCP system is designed as per the design considerations, the maximum RPM in the initial CBM well life may be limited by the pulley ratio (driven pulley diameter: driving pulley diameter) while the torque imparting capability of the motor at later stages may be limited by the motor frequency at the later stages of the well life. Hence, simulations for different run scenarios (water levels and flow rates) were done in C-Fer PC-Pump software for two cases taking Pulley Ratio as 4.74 and 6.22. The authors have presented trends comparing important parameters namely Fluid Level-Surface Motor loading, Fluid Level-Maximum Rod Torque and Fluid Flow Rate-Pump Speed. Based on the interpretation of these results, it was decided to experiment with two different driving pulleys for changing the pulley ratio during the well life to optimize the PCP system instead of upsizing the motor. This field trial was successfully conducted in Well – B and the parameters and the results are clearly depicted in the paper. Changing the pulley ratio over CBM well life will fulfill the torque and power requirements at the required pump RPM with significant cost savings by eliminating the need to install a new motor.
Energy Efficiency and Cost Optimization Assessments in Mangala Processing Terminal.
Authors: Kukadiya K. N. , Gajendran B. 
Published: April 2017

Abstract
This paper presents a remarkable insight on energy efficiency and cost optimization executed in Mangala Processing Terminal (MPT), an oil field block of Cairn India Limited (CIL) in Rajasthan. The process of optimization involves data analysis and mass balance prudently analyzing the bottle necks and addressing the issues with recommended outcomes. The optimization technique, thus implemented, caused overall operational cost reduction and energy saving as the consequences in its initial phase of implementation. Energy import reduced by about 50% and operational cost was cut down by approximately $350K/mnth.
Radial Jet Drilling in Mature Fields of Oil India Limited- An Experimental Approach
Authors: Jain Deepak , Maut Pratha Protim , Saharia Pranjal , Dutta Ranjit , Yomdo Saloma , Hatchell Ian , Mukherjee Aditya 
Published: April 2017

Abstract
Radial jet drilling was applied recently on an experimental basis in Oil India Limited (OIL) to retrieve production from some locked up potential in reservoirs with low permeability and near well bore formation damage, through enhanced exposure, with an ultimate objective of maximizing the total long-term hydrocarbon recovery from the reservoirs.
Radial drilling is a Frac-Less well stimulation technique used worldwide by Exploration and Production (E&P) companies to enhance production from depleted/damaged reservoirs. This well intervention technique involves milling of a 22 mm hole in the production casing of the mother well and then creating holes of approximately 50 mm OD with a maximum length of 100 m in the reservoir by removal of material from the formation using high hydraulic jetting pressure. Radial drilling is a proven technique to bypass the damage near wellbore zones.
The Paper depicts the successful completion of radial drilling operations in Four (4) nos. of pilot wells (3 oil well & 1 gas well) in four (4) different reservoirs of Oil India Limited, a post job production analysis and technical learning's from the Project.
The depth of the target zones varied from 2407 m to a record depth of around 3226 m (deepest well in India where Radial Drilling has been implemented). The first pilot well was completed with 3 laterals (length 29.5 m-100 m) with 900 phasing. The second well had 5 laterals (length 30 m-100 m) with 900 phasing in two different reservoir depths. The third well was completed with 4 laterals (length 97 m- 100 m) while the fourth pilot well was successfully completed with 8 laterals of length 50 m each at two different reservoir depths.
Post radial drilling production performance of the wells have been analysed and covered in the Paper. Significant increase in production was observed in the first three (3) wells, however no improvement in production could be achieved from the fourth pilot which was a gas well.
Mechanically, the application of this technology has been a complete success with all laterals drilled in the selected mother wells.
The technical experience and knowledge gathered from the pilot radial drilling campaign certainly presents an opportunity to unlock untapped potential for incremental production for future similar wellbore and reservoir conditions in Oil India Limited (OIL) as well as in other Exploration and Production (E&P) operators worldwide.
Maximizing Profits in a Tight Gas Volcanic Reservoir with a SIMOPS Multistage Fracturing Campaign
Authors: Sidharth Punj , Tiwari Shobhit , Anand Saurabh , Goyal Rajat , Agarwal Aman , Sharma Amit , Singh Mukund , Aggarwal Vishal 
Published: April 2017

Abstract
This paper presents success story of a SIMOPS multistage fracturing campaign peformed in Raageshwari Deep Gas field of India to produce from tight retrograde gas producing reservoir. Usually hydraulic fracturing in India is performed on a few selected candidate wells of a field with treatment frequencies ranging anywhere between 1-20 hydraulic fracturing treatments per year for a field. This is a well centric approach where individual services such as Eline perforations, CTU clean out, Well Testing etc operate in silos. The focus in this well centric approach is on optimizing each individual operation. On the other hand SIMOPS multistage fracturing campaign adopts an integrated approach and various services operate simultaneously on adjacent wells of same well pad. The focus in SIMOPS is on optimizing overall operations and can be considered a field centric approach. Accordingly average well completions cost and time is lower for integrated operations approach as compared to single well centric approach. CAPEX on the other hand is higher for SIMOPS approach since the number of wells being completed is higher and the scale of operations is much bigger than that of a single well approach. SIMOPS approach is more suited for tight reservoirs where economic production cannot be achieved without hydraulic fracturing. Raageshwari is a laminated tight retrograde gas producing reservoir and wells in this field do not produce economically without hydraulic fracturing (Gupta 2015). Each hydraulic fracturing treatment targeted multiple clusters of perforations and multiple such hydraulic fracturing treatments were required on each well to achieve full pay zone coverage of gross thickness ~ 700m on each well. The number of clusters completed in each treatment varied from 2-6 and number of treatments performed on a well varied from 5-10. High fracturing treatment frequency and a need to reduce average well completions cost paved way for the first SIMOPS multistage fracturing campaign in India.
Fractured Basement Reservoir Characterization in Barmer Basin
Authors: Singh Nepal 
Published: April 2017

Abstract
Weathered and fractured crystalline Basement emerged as the important unconventional play in the Barmer Basin. Natural fractures play a very significant role in the migration and hydrocarbon storage in crystalline fractured and weathered crystalline Basement reservoirs. Complexity and heterogeneity of the fracture network in the basement is a challenge to the geoscientist. This requires precise fracture characterization which is very significant for estimating the hydrocarbon potential as well as development of these reservoirs. A novel approach of integrating the seismic geometrical and stratigraphic attributes, with the borehole image logs and core data were found to be useful to characterize fractured and weathered crystalline basement reservoir in the Saraswati Field located in the eastern margin of Barmer basin. Seismic data derived Ant track volume calibrated with the core and bore hole image data has predicted NNW-SSE and NE-SW trending natural fractures information. Acoustic impedance and RMS seismic amplitude attributes identified the zones of intense fractured and weathered Basement. Assessment of the natural fracture network helped for appraising the Basement discovery as well as for designing the optimal well path for intersecting the maximum number of fractures for better reservoir performance.
Comprehensive Field Development Design for a Tight Gas Chalk-Reservoir in North Sea: A Capstone Design Project
Authors: Ansari Arsalan Arshad , Ghosh Bisweswar , Alklih Mohamed Yousef , Najy Anas K. , Nagah Adnan , Shafik Mohamed Mohsen 
Published: April 2017

Abstract
The petroleum industry is faced with a number of enormous challenges resulting from the declining oil prices such as high abandonment and new wells construction costs, low sweep efficiency, harsh environments etc. These challenges can be met by designing a long term field development plan of a petroleum prospect, ensuring maximum recovery without sacrificing the safety standards. This work describes a multicomponent and strategic development plan designed for a tight gas reservoir, starting from formation evaluation to drilling-completion and economic analysis in addition to the environmental issues that must be considered in advance.
The authors also acknowledge the support of:
The field is principally a gas condensate field, where the reservoir is mainly Chalk with an average porosity of 27% and average permeability of 0.1mD with 65% water saturation. The reservoir pressure (5960 psia) and dew point (5940 psia) being very close, the reservoir is close to saturation pressure and gas condensate is expected to form immediately on commencing production. PVT studies indicated that the critical condensate saturation will not be reached which in turn means that it will never be mobile or recoverable with reservoir pressure decline. Given the fact that the water drive is rather weak, pressure maintenance methods will be needed to avoid the condensation of gas within the reservoir.
Based on petro-physical evaluation, our team was able to construct a static reservoir model using Petrel Software and the team suggested three different development scenarios consisting of horizontal and multilateral wells of various configurations. Based on the development strategies, a dynamic model is constructed for each scenario to compare the techno-economic feasibility and selection of the most optimum strategy. It was found that the field would be economically viable to produce for a time period of 50 years and the simulation results indicate that an ultimate recovery of 69-76% was achieved if water injection is applied from year-1 onwards. Moreover, the highest recovery factor of 76% is achieved with scenario-B as it has a five spot pattern with 8 vertical injection and 3 multilateral production wells. In addition, the most delayed water breakthrough is achieved in this scenario that occurs after 2.5 years. Moreover, it was also observed that the pressure maintenance was 100% effective in scenario-C as the reservoir pressure increased as a result of increasing the water injection rate rather than increasing the sweep efficiency. However, for the other scenarios, the reservoir pressure drops but not below the critical value.
Finally, a cumulative gas production of 389-424 MMMSCF was observed along with a gas production rate of 8.61-24.7MMSCF/day giving a cumulative net present value of $890,000 with a payback period of 5 years, indicating that the project is economically viable after 50 years.
Ultra-Light Weight Proppant and Pumping Design Lead to Greater Conductive Fracture Area in Unconventional Reservoirs
Authors: Bestaoui-Spurr Naima , Hudson Harold 
Published: April 2017

Abstract
The oil and gas industry has been relying on hydraulic fracturing techniques to proliferate production from low permeability reservoirs. Despite significant advancements in tools and chemicals used in the fracturing processes, maximized production and recovery of hydrocarbons is still unattainable due to challenges with proppant placement and settling.
Even when heavy gelation fluids are used, proppants suspensions are subject to particles settling in the presence of vibration, and/or due to fracturing fluids breaking before the fracture close. Furthermore, the fractures are typically vertical; in this case the proppant has a tendency to settle in the lower portion of the fractures while the upper portions close in the absence of proppant. This can lead to impairment in the geometry of the fracture and well productivity.
This paper describe a new ultra-lightweight proppant having a low specific gravity (1.06) that can withstand stresses up to 8,000 psi at a temperature of 275°F. Such proppant is easier to transport and due to its buoyancy will stay suspended in low viscosity fluids leading to fractures that are much better propped.
This new material has been fully characterized for its properties including mechanical and thermal properties. It applicability to far field applications has been validated through conductivity testing in a partial monolayer mode as a function of loading and temperature. The Modeling was used to establish its application in mixtures with conventional proppant for vertical coverage of the fracture.
Experimental evaluation of the proppant show that its conductivity decreases as the stress and temperature increase due to the nature of the material. The results show that this proppant can be used up to 8,000 psi at 275°F in a partial monolayer mode. Placing the proppant in a partial monolayer application is required due to the flexibility of the proppant material and to maximize conductivity through the proppant.