bluuebunny/crossref_metadata_2025_split huggingface dataset:
Designing a Core Analysis Programme for the Mangala, Bhagyam and Aishwariya Fields—Ensuring Value for Money
Authors: O'Sullivan T. , Beliveau D. , Kumar H. 
Published: March 2008

Abstract
The Mangala, Bhagyam and Aishwariya fields are located in Rajasthan and collectively contain approximately 2 billion barrels of STOIIP. During the appraisal of these fields, more than 1.7 kilometers of core was collected from the principal reservoir, the Fatehgarh Group Formation.
This paper illustrates the methodology used to highgrade the geological units and pick specific points for special core analyses so that maximum technical information was gained for minimum cost. The criteria considered for highgrading the points were a combination of STOIIP content, facies type and porosity-permeability variation.
Sensitivities were also run on the parameters that are input to the STOIIP calculation and recovery estimates to ensure that adequate analyses had been conducted on the key parameters. The approach as defined in this paper enabled a significant increase in STOIIP for these fields that could be clearly demonstrated and supported by the core analysis data.
Mangala Field Permeability Measurements: Comparison of Core, Wireline and Well Test Data
Authors: O'Sullivan T. , Beliveau D. , Praveer K. , Tandon R. 
Published: March 2008

Abstract
Permeability is a measure of the ability of a reservoir rock to transmit fluids, and is arguably the most important parameter within a simulation model. For the Mangala field, permeability has been measured extensively from core analyses, wireline logging and well test analyses. Implicit in each of these measurement techniques is a specific scale and measurement direction. It is thus not surprising that differences still remain even after correcting the measured permeabilities from various sources to an absolute permeability.
This paper presents the detailed methodology that was used for the calculation of permeability from the various sources and discusses possible explanations for the differences in the numbers.
In some of the lower reservoir units, Mangala core permeabilities are significantly higher than the permeabilities measured from well tests, and it is proposed that permeability "baffles" on a multi-meter scale may be causing this decrease in well test permeabilities. These "baffles" are related to depositional features (e.g. current bedding and channel pinch-outs) and are likely to be strongly directional, leading to a horizontal permeability anisotropy which has important implications for reservoir development.
Underwater Laser Drilling: Drilling Underwater Granite by CO2 Laser
Authors: Kobayashi Toshio , Nakamura Masahiro , Okatsu Komei , Ohtani Kiyonobu , Takayama Kazuyoshi 
Published: March 2008

Abstract
The purpose of this research is to develop Underwater Laser Drilling Technology in drilling and completing oil and natural gas wells. Recent challenges in oil fields are caused by: the geometry of oil or gas wells is becoming more complicated in profile; drilling in hard formations like granite requires more tripping times for changing rotary bits made of steel; as the water depth at which floater rigs can operate increases, tripping has to take longer than ever. Underwater Laser Drilling is a key to solution of these challenges since the laser may allow for non-contact / non-rotating drilling method. Granite is one of the most difficult rocks to be drilled by lasers. Consequently, no successful report has been found on underwater granites drilled by lasers. This paper describes experimental tests of irradiating carbon dioxide (CO2) laser to granite submerged in water/bentonite solutions. Sample granite was submerged at 50mm from the water-surface and then a CO2 laser with a wavelength of 10.6μm which has a high absorption coefficient in water was intermittently irradiated into the 4wt% bentonite solutions. A laser induced underwater shock waves, cavitation bubble formations, and micro-water jet formations upon bubble collapse. The high power laser beam locally melted the granite into molten glass, which successively turned to a molten glass bead. The generated glass beads were small enough to be removed out of the created hole. A high-speed video camera was employed to record the laser beam in the water. We observed the generation of initial cone shaped water bubbles through which the laser beams reached bottom rock surface with a minimum absorption energy loss. The laser beam indeed drilled the granite specimen submerged in the solution. The research will continue to collect data for designing a prototype.
Upgridding 3-D Geologic Models in a Channel-type Environment
Authors: Talbert Matthew , Ma Xianlin , Datta-Gupta Akhil 
Published: March 2008

Abstract
The development of coarsened reservoir simulation models from high resolution geologic models is a critical step in a simulation study. The ‘optimal' coarsening becomes particularly challenging in a fluvial channel environment where the channel sinuosity and orientation can result in pay/non-pay juxtaposition in many regions of the geologic model. Under such conditions, a uniform coarsening will result in mixing of pay and non-pay and will most likely result in geologically unrealistic simulation models and erroneous performance predictions. In particular, the upgridding algorithm must keep pay and non-pay distinct through a nonuniform coarsening of the geologic models. In this paper we present a coarsening algorithm to determine an ‘optimal’ reservoir simulation grid by grouping fine scale geologic model cells into effective simulation cells. Our algorithm groups the layers in such a way that the heterogeneity measure of an appropriately defined ‘static’ property is minimized within the layers and maximized between the layers. The optimal number of layers is then selected based on an analysis resulting in the minimum loss of heterogeneity because of upgridding. We demonstrate the application of the optimal gridding by history matching waterflooding in a structurally complex and faulted offshore turbiditic oil reservoir. The field is located in a prolific hydrocarbon basin offshore South America. Permeability and fault transmissibility are the main uncertainties. More than 10 years of production data from up to 8 producing wells are available for history matching. We demonstrate that any coarsening beyond the degree indicated by our analysis overly homogenizes the properties on the simulation grid and alters the reservoir response.
Pipeline Maintenance and Management in Inter-tidal Region - A Case Study
Authors: Pant Himanshu , Kumar Ujjwal 
Published: March 2008

Abstract
The pipeline system is regarded as the safest and the most economical system for transportation of hydrocarbons across the country. Pipelines of various sizes and lengths crisscross the continents supplying both processed as well as unprocessed crude oil and gas from the producing region to the consumer.
Though the advent of pipeline and its development occurred concurrently with the development of the hydrocarbon industry, but like the oil industry, the pipelines also keep on throwing new challenges requiring human ingenuity.
The present paper presents the approach taken by the National Oil Company of India in maintaining and operating a 36" pipeline transporting unprocessed sour gas (150-160 ppm of H2S and nearly 7% CO2) from offshore field to the onshore gas processing plant.
The paper explores the various options evaluated to maintain the health of the pipeline which travels through various profiles with special attention to the landfall point, where the pipeline faces alternating exposure of a dynamic meandering river which has changed its course many a times resulting in generation of free spans.
Techniques in Marginal and Mature Fields in the Pannonian Basin, Hungary: Case Study
Authors: Holoda A. , Palásthy Gy. 
Published: March 2008

Abstract
In Hungary the oil production started in the middle of 30's in the last century. Intensive exploration activity in the region had resulted sustainable increase in the recoverable oil and gas reserves. In the early 80's, however, this tendency stopped, the size of new discoveries have been continuously decreasing consequently a declining phase in the production pointed out the importance of rejuvenation of the existing mature and marginal fields. Production operation of the large fields required more attention and finding all the stranded barrels of HC became a strategically important company task including but not limited to research and introduction of new EOR/IOR technologies.
MOL, as one of the largest operators in the region has introduced and successfully implemented wide spectrum of enhanced and improved techniques in the maturing oil fields. Application of horizontal wells, infill drilling, 3D seismic programs, state of the art geological modelling, methane and CO2 injection, improved water flooding will be presented highlighting the added values of different solutions in these projects. Currently MOL operates more than 100 fields in the Pannonian basin. Recovery factor of these fields exceeds 35-40% for oil and 60-75% for gas. How to progress: cost effective solutions or more expensive new technologies are the better approach? This paper will deliver some exciting examples for both situations.
Microbial Enhanced Oil Recovery (MEOR) with Special Emphasis to the "Uneconomical Reserves"
Authors: Rafique Maqsood Ahmad , Ali Usman 
Published: March 2008

Abstract
While demand for petroleum products continuous to rise, petroleum production worldwide is in a steady decline. However, new developments in technology and the rise in world oil prices give promise that substantial portions of otherwise neglected oil can be recovered. So in the continues race of exploring petroleum, recovery of known reserves must be improved if the goal of avoiding shortages is to be met.
One of the promising recovery methods is the microbiological enhanced oil recovery (MEOR). MEOR technology has the potential to be one of the reliable technologies that suits best the economic constraints of the current oil markets. The technology is a potential alternative to other EOR/ IOR methods, as it is being implementing in most parts of the world with satisfactory results not only from economics point of view but also from having lesser environmental impact.
The paper provides a review on MEOR technology and discusses it with special emphasis to marginal and/or uneconomical reserves. The goal of cost reduction, which is a major objective in any recovery methods, can be met by using MEOR technology which involves injecting a small amount of a solution containing microorganisms to spread through the reservoir and consequently produce desirable chemicals and gases that will enhance oil recovery and therefore profit. The paper also outlines the strategies to identify and meet the challenge of recovering large proportions of oil using MEOR techniques which could be very helpful in closing the energy gap by draining large proportions of oil which is left behind and minimizing the supply and demand difference in today's "energy hungry world".
Novel Liner System Improves Coring Performance, Rig Safety, and Wellsite Core Processing
Authors: Hall Larry M. , Wilson Bob T. , Norrie Alan G. 
Published: March 2008

Abstract
A one-piece aluminum inner barrel liner system has been employed to protect and containerize core material during coring operations with conventional and wireline core barrels. The system offered enhanced safety features and improved core handling on the rig floor. The integral one-piece liners securely containerized the core during acquisition. Vent holes allowed expelled gas to escape during recovery to the surface, improving safety during core retrieval and handling. The companion Non-Rotating Inner Tube Stabilizer system will ease separation of the 30-foot liner joints, thus improving wellsite handling procedures and safety during extended core runs. The design allowed the liners to be opened quickly and easily at the surface for rapid examination and sub-sampling of the core material.
Lessons Learnt from over 20 Years of 4-D Deployment
Authors: Foster Dave G. 
Published: March 2008

Abstract
This paper reflects back on the major trends, successes and lessons learnt of BP's 4-D deployment over the last 20 years, and offers insights into the main considerations for developing 4-D strategy in emerging areas.
Since the early 1990's, BP has been developing and deploying 4-D technologies across a range of different environments and reservoir situations. Up to the end of 2007, over 115 surveys have been acquired*, about 85 operated and 30 non-operated. This experience base represents a significant proportion of industry 4-D history, and when analysed, can offer valuable insights into developing future 4-D strategy and tactics for new fields and basins. 4-D has most commonly been used in oilfields under water-flood due to the ease of monitoring large saturation and pressure changes and the increased complexity of reservoir management, which gives the opportunity for large commercial impact. Monitoring of gas field depletion has added clear value in appropriate situations, but is much less common due to the generally simpler reservoir management issues and smaller infill programs. The dominant acquisition technology deployed has been towed streamer surveys every 25 years, but BP has now also installed the world's first three permanent ocean bottom cable (OBC) monitoring systems to deliver high-quality and frequent 3-D and 4-D data.
4-D application is continuing to expand globally, and BP itself is currently expanding 4-D application from the historical core areas of the North Sea and Gulf-of-Mexico into regions of new and existing production, such as deepwater Angola, and Alaska respectively. Development of 4-D strategies for new areas and basins requires an assessment of both technical and commercial applicability.
Monitoring of Polymer flood project at Sanand field of India
Authors: Dass Chanchal , Jain Manisha Ajay , Dhawan Ashwani Kumar , Misra Tilak Ram 
Published: March 2008

Abstract
Sanand is the only oil field in India where field-scale polymer flooding is going on for the last twelve years. The field was discovered in 1962 and commercial production commenced from 1969. In view of high mobility contrast and predicted poor recovery of around 15% of OIIP under depletion drive, polymer flooding was adopted as an IOR process for improving oil recovery from this field. An inverted five spot polymer pilot project was started in 1985. Based on the encouraging result of the pilot, the polymer injection project was expanded to a larger area in 1993 and field-scale implementation has commenced from 1995. As on July 2007, the recovery from the field is around 24% with 68% water cut. Envisaged recovery from the field is around 36% with 77% water cut by 2020 with continuance of polymer injection up to 2013 followed by chase water.
Maintenance of quality of polymer solution and chase water for such a long period is a real challenge to the professionals associated with the project and plays a key role for the success of the polymer injection project. For this, continuous surveillance of the entire process is required to ensure effectiveness of the project and take mid course correction, if required. The different monitoring aspects involve in the process are-a) performance of producers, b) rheology of polymer at different points of injection system, c) water quality and other parameters affecting the polymer viscosity, such as dissolved oxygen, bacterial activity and d) injection well rate, pressure and performance.
This paper aims to present main practices followed for maintaining the quality of injection polymer/chase water and other process parameters and to show how it has helped to improve the efficiency and effectiveness of the polymer IOR technique in Sanand field.
Optimized Hydrualic Fracturing for the Gandhar Field
Authors: Sagar Rajiv , Pandey A. K. , Prasad Durga , Vinod A. K. , Panse Rohit , Nugraha Ikhsan , Taneja Pankaj 
Published: March 2008

Abstract
Gandhar is one of ONGC's major brownfields, discovered in 1983 and located in Gujarat. The Field produces approximately 30,000 bopd and is on decline.
A joint team from ONGC and Schlumberger carried out a rigorous process of candidate selection, fracture design, and implementation of fit-for-purpose technologies.
10 candidate wells were selected and the target zone was the GS-3A reservoir. 10-15ft above the GS-3A was a water bearing sand. Most of the candidate wells were primarily in an area of the reservoir that had experienced poor recovery primarily because of poor permeability.
There were unique challenges posed by the Gandhar candidate wells. Earlier attempts to fracture wells had been unsuccessful. In addition the water bearing sand posed a risk to successful execution; the fracture had to be contained within the zone of interest. High Pressure and high temperature operations posed additional challenges that had to be addressed.
For Fracture containment Schlumberger's Sonic Scanner tool provided rock mechanical stress data that was used to design the fracture to be contained within the zone of interest and not break into the water bearing sand above. It also provided the maximum stress direction to determine the preferred orientation plane for perforating. Oriented perforating assisted in achieving lower fracture breakdown pressures.
Fracturing fluids for high temperature (320 degF) operations were selected. Well design and equipment was considered for high pressure operations (10,000 psi surface pressure)
Using this process, 10 wells were successfully hydraulically fractured. Unfortunately, wells produced lower than expected; unforeseen in-situ emulsions are suspected as the cause for the production impairment.
In this paper we will describe the technology and processes brought to the project. Current results and impairment issues will also be presented.
New Completion Technology As A Catalyst to Improve Oil Recovery
Authors: El-Abd Salem , Amiri Abdel Hameed , Keshka Ashraf , Al-Bakr Salem , Al Arfi Saif , El-Asmar Magdi 
Published: March 2008

Abstract
This paper presents the reservoir considerations, implementation and results of a new completion technology with the aim to improve ultimate recovery. The non-uniform production profile across the horizontal hole especially in the highly heterogeneous and fractured reservoirs can result in premature water production and lower ultimate recovery. PLT surveys were carried out in some horizontal wells which indicated non-uniform production profile across the horizontal holes. Therefore the need for production system as part of the completion was raised to control water production and to improve ultimate recovery. This completion technique will the low and high permeability intervals to contribute to flow was found to be the optimum option for this highly heterogeneous and fractured reservoir.
Horizontal hole segmentation using ICD (Inflow Control Device) completion was found to be the optimum option to be tested as pilot in a new and an existing wells. The new well was expected to penetrate highly fractured area and the existing well is also located in highly fractured area.
The ICD Equalizer system was installed in both wells to evaluate the technique. The surface testing results of the re-completed well indicated a drop in the well water cut from 7% to traces. PLT survey was carried out in both wells and indicated uniform production profile across the horizontal section. Therefore the reliability of the technique was proved and these jobs were considered as the first application in United Arab Emirates. With field scale implementation, the reservoir simulation and economic analysis revealed an improved oil recovery of 1% and higher NPV.
Integrated Permeability Modeling Using Wireline Logs, Core and DST Data in a Deepwater Reservoir
Authors: Taware Satyajit , Taware Anuradha , Sinha Amit , Jamkhindikar Atul , Talukdar Ramen , Datta-Gupta Akhil 
Published: March 2008

Abstract
Reservoir characterization requires accurate estimates of permeability. The commonly used porosity-permeability transforms are often inadequate as permeability is also a function of clay distribution, sorting, pore connectivity, tortuosity and variations in other petrophysical properties. More robust permeability estimation can be made by integrating multiple logs in the transform instead of just porosity.
This paper deals with a novel technique for deriving permeability by correlating multiple well logs with core permeability using non-parametric regression methods. First, we classify the well log data into electrofacies based on the ‘similarity’ of their response. This electrofacies classification does not require any artificial subdivision of the data population but follows naturally based on the unique data values reflecting minerals and lithofacies. A combination of principal component and model-based cluster analysis are used to characterize the electrofacies. Secondly, we apply a non-parametric regression technique to predict permeability using well logs within each electrofacies. The main advantage of this technique is that it is primarily data-driven as opposed to model driven and does not require a priori specification of functional forms, which makes conventional multiple regressions difficult and often biased.
The proposed technique was used in a deepwater reservoir system consisting of thick massive sand beds along with thinly bedded sand-shale sequences. The work flow consists of electrofacies identification, facies-wise permeability transform generation, calibration with DST data, and finally permeability population in the geological model using cloud transforms and Sequential Gaussian Simulation (SGS). The permeability transforms generated from core and well log data were validated via blind tests whereby we predicted permeability in another cored well that was not included in the correlation. For further validation, we also used the transform-derived permeabilities in analyzing the DST results in a blind well where a laminated sand section was tested. A reasonable match of the permeability-thickness product was observed. Finally, the permeability transforms were integrated into a 3-D geologic modeling using SGS and cloud transform. It was observed that our approach correctly captured the porosity-permeability scatter in the geologic model for various facies groups.