bluuebunny/crossref_metadata_2025_split huggingface dataset:
Identification of Seismic Geomorphic Features with Hydrocarbon Indicators in the Deepwater Andaman Basin, India
Authors: Nandi A. K. , Samanta B. G. 
Published: January 2012

Abstract
High quality 3D seismic data has facilitated the use of seismic geomorphology in identifying features of hydrocarbon indication in the deep waters of Andaman Basin to the east of Andaman islands. In Andaman basin, presence of various seismic geomorphic features like turbidity-flow leveed channels, channel overbank sediment waves, crevasse splay/ overbank splay deposits, frontal splays or fan lobes, debris flow deposits etc. have been reported (Nandi et. al., 2009). Additionally, these areas show presence of direct hydrocarbon indicators (DHI) within the Neogene sediments and that makes the hydrocarbon exploration in the area quite interesting. The 3D seismic data with its seismic time slices, horizon slices and interval attributes provides images of deepwater depositional systems in a map view that can be analyzed in the light of classical geomorphological concepts (Posamentier and Kolla, 2003).
An attempt has been made to study all features depicting hydrocarbon indications by applying the concept of seismic geomorphology. These are gas chimneys, gas clouds, BSR, flat spots, seismically obscured areas, charged channels and pockmarks. In the study area, the charged channels with gas chimney like features are common in the back-arc part of the basin whereas such channels are less in the fore-arc part of the basin. This may be attributed to the frequent tectonic disturbances in the back-arc part and its nearness to the spreading center in between Alcock and Sewell rises. All these features of hydrocarbon indications give rise to the expectation of a breakthrough in the form of an major discovery of hydrocarbons in the deepwater areas of Andaman.
Improving Oil Recovery and Injection Strategy in Shallow Reservoir (Rindu Reservoir) of Area 3&4 Duri Steam Flood
Authors: Lumbantobing Sudianto , Natalia Sandra , Silalahi Henri Sahat 
Published: January 2012

Abstract
The Rindu reservoir of Area 3&4 Duri Field has been developed economically since 1994. Since it is shallow reservoir and penetrated by existing PK producer wells, the Rindu reservoir is started producing commingles with PK sand in 1997 (Rindu Vertical Expansion/ RVE well). In alignment to this effort, the Rindu injection also started at the same year. After 8 years production-injection, these commingle producers have poor production performance due to back pressure, cross-flow, and scaling.
Through heat management review, it was found that Rindu in the southern Area 3&4 has longer maturity response, poorer injection (200 BSPD), and longer heating time (~80 years).
An integrated geological and reservoir engineering study of Rindu performance is carry out to define improvement production and steam injection in southern part Area 3,4. The study resulting some key finding:
Rindu and PK have significant reservoir pressure and temperature different. All poor performance RVE producers are facing cross flow/backpressure and scaling problem Low drainages point in Rindu pattern resulting high reservoir pressure Low injection performance controlled by high backpressure Southern Area 4 Rindu sand has a poorer reservoir quality compare to Northern part.
The project team proposed to drill separate Rindu only to avoid cross-flow, back pressure, or scaling issues. At the same time it improved Rindu pattern drainage points. The project also proposed to increase steam injection rate gradually after reservoir pressure decreased. After completing the project, the Rindu reservoir deliver 50 BOPD/well, increase steam injection by 500% (1000 BSPD), accelerate pattern heating process (~2.5 years), and better reservoir management.
This study recommends developing Rindu and PK reservoir separately. Injectivity improvement will be resolved through completing pattern drainage points and deliver better reservoir heat management.
Reservoir Risk Assessment in Turbiditic Slope Channels: A Case Study from the Kutei Basin (Offshore Kalimantan, Indonesia)
Authors: Caselgrandi E. , Cavanna G. , Corti E. , Della Rossa E. L. , Rovellini M. E. , Suhardiman Y. , Cerutti A. , Sugama C. 
Published: January 2012

Abstract
The studied reservoir consists of turbiditic slope channels which form elongated sandy bodies with dimension of 4 to 12 Km in length and 1 to 4 Km in width. The thickness is varying from few metres to almost one hundred. These channels are hydraulically separated and characterized by high values of porosity and permeability.
These sand bodies were identified and porosity characterized by means of seismic data. The first three wells have proved the correlation between gas-bearing sands and "low-impedance" seismic responses. Nevertheless, since those wells did not cross all the sand bodies (only 6 out of 14) the main problem at that stage was the risk assessment of the hydrocarbon occurrence in the remaining bodies.
In order to assess this risk the first approach was to identify, for all the bodies, relevant seismic criteria (Amplitude strength, Signal noisiness, Fragmentation and Recon AVO) to use for a qualitative evaluation defining a ranking of the undrilled bodies. The following step was to apply a Bayesian approach to assess the relevant probability of hydrocarbon occurrence. This technique requires the estimation of two parameters: prior probability based on geological area knowledge and likelihood derived from seismic indicators.
On the base of the probability ranking a limited number of scenarios was defined. For each scenario a dedicated plan of development was assigned. A new appraisal well was drilled after this evaluation. This allowed verifying the validity of the ranking system used to estimate probability of success with regards to the undrilled segments. The results show good agreement between seismic data and well’s results with one (positive) exception.
Moreover a traditional "Risk Analysis" was performed in perforated bodies to sample all the critical parameters (static and dynamic) and to build several models. By these models a set of volumetrics and production profiles were obtained.
Quantification of Drillstring Integrity Failure Risk Using Real-Time Vibration Measurements
Authors: Arevalo Yezid , Fernandes Ashley 
Published: January 2012

Abstract
Vibration measurements have traditionally targeted the improvement of downhole tool reliability. This paper targets the effects of vibration on the complete drillstring. Failures associated with drillstring vibration continue to happen in spite of the sophistication of today’s measurements. These failures represent a very significant amount of lost time which we target to improve.
The industry has a limited knowledge database or tools for managing and quantifying the risk of vibration to the complete drillstring. Operators are faced with an unknown quantification of the risk severity when attempting to mitigate vibration. By quantifying the risk, this work demonstrates how the prevention of incidents can be achieved. These incidents include, but are not limited to, twistoffs, backoffs, and bottomhole assembly (BHA) component failures.
The proposed solution is based on real-time measurements of drillstring vibration to estimate an ongoing drillstring integrity risk which is used as a guideline to improve decisions while drilling the well. This solution has been developed using advanced vibration sensors to discriminate between different types of vibration. This was critical to estimating realistic cumulative damage to the drillstring, which is highly dependent on the type of vibration suffered by the assembly and the onset of vibration modes coupling.
This paper shows that approximately 80% of drillstring integrity failures analysed can be identified and prevented using the proposed risk quantification solution. This result has been obtained despite the fact that fatigue or wear of drillstring components prior to a run is unknown and vibration sensors were located at a single position in the drillstring. This indicates that the primary contributor to drillstring failures is the drilling conditions for any given run.
Slimhole Wells at the Raageshwari Deep Gas Field
Authors: Crighton Alan , Peytchev Peter , Upadhyay Abhishek , Doodraj Sunil , Malik Sumit D. , Varghese Roy , Sawyer Graham , Lochhead Ian , Meempat Balu Govind 
Published: January 2012

Abstract
During exploration activities in the Thar Desert of Rajasthan, India, Cairn India Ltd. discovered numerous oil fields in the Barmer Basin. The oil reservoirs are relatively shallow and benign in terms of pressure, temperature and corrosivity, but they posed significant flow assurance challenges due to relatively high crude viscosity, wax content and pour point. As a result, surface facilities are reliant on heat for flow assurance. Total reliability of power and fuel supply for the facilities was essential to ensure export product quality and for flow assurance for the waxy oil.
The paper presents Cairn’s approach of utilizing state-of-the-art technology that integrates all relevant data scenarios for the drilling and production systems for this lean gas condensate reservoir. This development will provide the necessary power and heating fuel supply and the primary gas supply for the main oil processing terminals and for power generation stations along a 600km heated export pipeline.through the end-of-life for the major oilfields discovered in Western Rajasthan, India.
Raageshwari Deep wells target tight, predominantly volcanic reservoirs with cost-effective monobore designs that include multiple fracture stimulations in various pay zones to maximize well productivity. The slimhole well design, dynamic completion design, and careful bit design and selection successfully enabled the drilling of these wells with 26% cost savings on the total budget for drilling ten wells ($ 2M per well). A program highlight was the drilling of volcanic tuff formations in a single run.
The paper will describe detail aspects of monobore well planning and well design implementation including fracture stimulations. It will also demonstrate how this significantly improved the well delivery that contributed to effective development plans for these major oilfields.
Offshore Gas Condensate Field History-Match and Predictions: Ensuring Probabilistic Forecasts Are Built With Diversity in Mind
Authors: Gross Herve , Honarkhah Mehrdad , Chen Yuguang 
Published: January 2012

Abstract
Ideally, probabilistic forecasts improve the decision quality, capture upsides and mitigate downsides. Unfortunately, one of the risks associated with probabilistic forecasts is the possible creation of a large number of models with similar properties or responses. Methods to identify representative models from an ensemble of models are thus necessary.
In this paper, we extend the use of distance-based methods, developed at Stanford Center for Reservoir Forecasting, and Kernel clustering techniques to the selection of models for economic decision-making. Using mathematical tools, the large set of models in a high-dimensional space is mapped to a low-dimensional space and a distance function based on several prediction-related quantities is used to quantify the similarities and dissimilarities among an ensemble of history-matched models. We then construct a small portfolio of models with a diverse range of prediction performances for less cost-intensive probabilistic forecasts.
The approach is applied to an offshore gas condensate field in the Asia-Pacific region. Two possible development plans were competing: continue to produce from existing geological structures, or extend the development to accumulations connected through a saddle in the carbonate reservoir. The decision was impacted by the uncertainty on remaining volumes in place and connectivity between structures.
Based on the uncertainty management plans, 925 history-matched models are generated with genetic algorithms. Within the context of distance-based modeling, an application-tailored distance function between models is designed, balancing static (scenario independent) and dynamic (scenario dependent) properties of the models. Then, eight diverse and representative models are selected among the 925 models. We show that the eight selected models, while offering an equally good history-match, cover well the uncertainty ranges of the static and dynamic properties considered. The selected models can be used to evaluate different possible development scenarios for final business decision making.
Selecting Location for CO2 Storage in Indonesia: Risk Assessment on a Basinal Scale
Authors: Amijaya Donatus Hendra 
Published: January 2012

Abstract
CO2 capture and geological storage (CSS) is one alternative that offers a new set of options for reducing greenhouse gas emissions. The concepts of CO2 storage refer to the injection of carbon dioxide in dense form into aquifers, which basically must meet several conditions. Three types of geological formations that usually can be used for the geological storage of CO2 are oil and gas reservoirs, deep saline formations and unmineable coal beds. Indonesia has about 60 Tertiary sedimentary basins, however that great precautions must be taken for selecting particular sedimentary basin for carbon dioxide storage. Preliminary risk assessment can be conducted on basinal scale based on possibility of leakage and geothermal gradient. On basinal scale, sedimentary basins in Indonesia are of intermediate to high risk for CO2 storage.
The Best Practices In Moisture Control of Sour Natural Gas as Export Gas: Case Study on Line Water Content Analyzer Assessment in a Gas Plant
Authors: Bahmannia Gholamreza 
Published: January 2012

Abstract
The dry sour gas is 4th gas plant’s main product for transfer and injection into Aghajari Oil Field as EOR projects. Moisture control and monitoring in sour gas is a critical parameter because of severe corrosion problems that are associated with sour gas. For assessment of Michell online process moisture analyzers, in comparison to laboratory Michell’s ceramic moisture sensor and portable monitor (ASTM D-5454) and Chilled mirror device as manual dew point tester (ASTM D-1142), a periodical test has been done. The results showed acceptable accuracy range of online analyzers and the calibration period confirmed. In this paper all recorded data has analyzed by statistical methods.
Middle East Case-Study Review of a New Free-Pipe Log for Stuck-Pipe Determination and Pipe-Recovery Techniques
Authors: Torne Juan , Rourke Marvin , Derouen Brock , Kessler Calvin 
Published: January 2012

Abstract
Significant drilling challenges can exist when drilling in mature fields or in reservoirs that are subject to various geomechanical stress regimes associated with overpressure, tectonic stress, and depletion. Despite mitigation efforts to reduce stuck-pipe occurrences, drilling problems leading to stuck pipe still occur. When conventional techniques used to free the drillstring are ineffective, wireline logs are often run to determine the stuck depth of the drilling assembly and to release the pipe above the free point.
The traditional free-point (FP) logs used to determine the depth of stuck pipe are based on a measurement of strain when stress is applied to the pipe between two points. These measurements are taken at specific intervals and require the tool arms to firmly grip the pipe to prevent movement that could mask the strain measurement. This simple method is difficult to implement reliably. Because it depends on the skill of the specialist operator, pipe-recovery operations include "more art than science." A new technology, based on electromagnetic measurements, can now make a continuous FP log. The log consists of two passes, with and without stress applied to the pipe. By comparing the two responses, service company specialists and drilling engineers can interpret the log without the need for highly-experienced personnel.
This paper reviews several cases from the Middle East and provides information about the tool response in various parts of the drilling assembly. It also reviews pipe-recovery techniques that are recommended depending on the FP log response and the specific drilling assemblies, such as drill collar, drill pipe, crossovers, and jars. The pipe-recovery techniques discussed include explosive back-off techniques, explosive pipe severing, and various pipe cutters. The case study examples demonstrate the improved efficiency and reliability of determining stuck-pipe intervals and subsequent successful pipe recovery.
New and Improved Methods for Performing Rate-Transient Analysis of Shale Gas Reservoirs
Authors: Nobakht M. , Clarkson C. R. , Kaviani D. 
Published: January 2012

Abstract
Multi-fractured horizontal wells are currently the most popular method for exploiting low-permeability tight and shale gas reservoirs. Production data analysis is the most widely used tool for analyzing these reservoirs for the purpose of reserves estimation, hydraulic fracture stimulation optimization, and development planning (Ambrose et al., 2011). However, as pointed out by Clarkson et al. (2011), a fundamental problem with the application of conventional production data analysis to ultra-low permeability reservoirs is that current methods were derived with the assumption that flow can be described with Darcy’s law. This assumption may not be valid for tight/shale gas reservoirs, as they contain a wide distribution of pore sizes, including in some cases nanopores (Loucks et al., 2009). Therefore, the mean-free path of gas molecules may be comparable to or larger than the average effective rock pore throat radius causing the gas molecules to slip along pore surfaces. This results in slippage non-Darcy flow, which is not accounted for in conventional production data analysis.
Clarkson et al. (2011) modified the pseudo-variables used for analyzing gas reservoirs in production data analysis to account for slippage. They demonstrated that if the effect of slippage is not considered, it leads to noticeable errors in reservoir characterization. Clarkson et al. (2011) also mentioned that even after using the modified pseudo-variables, the values for permeability and fracture half-length do not exactly match the input data to simulation. In this paper, a methodology to properly analyze the production data from a fractured well in tight/shale gas reservoir producing under a constant flowing pressure in the presence of desorption and slippage is presented. This method uses new pseudo-time definition instead of conventional pseudo-time currently being used in production data analysis. The method is validated using a number of numerically-simulated cases. It is found that the newly-developed analytical method results in a more reliable estimate of fracture half-length or contacted matrix surface area, if permeability is known.
A Prediction of Water Breakthrough Time in Low-Perm Gas Reservoirs with Bottom Water
Authors: Zhang Qinghui , Li XiangFang , Song Zhaojie , Yan Bicheng , Yin Bangtang , Li Qian 
Published: January 2012

Abstract
For low permeability reservoirs with threshold pressure gradient, the dynamic of water coning is different from that in the conventional gas reservoir. If conventional prediction methods are applied to calculate the water coning time, errors occur and cannot reflect the real situation of the water coning. This paper considers the impact of threshold pressure gradient, modifies the process of gas flow and water coning and through mathematical deduction, this paper gets water breakthrough time prediction formula in low-perm gas reservoir with bottom water. Through calculation in cases, this paper preliminarily analyzes the effect of threshold pressure gradient on water breakthrough time. With an increase of threshold pressure gradient, the water breakthrough time decreases, and the gas well see water earlier.
A Review on Offshore Concepts and Feasbility Study Considerations
Authors: Maddahi Maryam , Mortazavi Seyed Javad 
Published: January 2012

Abstract
There is no doubt that choosing the excellent technology and operation is one of the keys to achieve sustainable global energy. With the quick advancement in the subsea technology and offshore industry and its influence on the global oil and gas production through the past three decades, an update working knowledge of engaged offshore facilities around the world seems to be essential for a successful petroleum field development. Selection of the most appropriate equipment and process through the early exploitation study stages of developing an offshore petroleum reservoir can determine the right facilities for delivering the greatest value.
The current paper gives an overview of characteristics, and features of offshore production facilities, their advantages and disadvantages according to the most common offshore system selection and feasibility studies considerations. It has been tried to point out the most important criteria of the related Issues and concerns during a process and facilities selection for a potential case of installing the subsea completion as well as proposing processes to help in selection of the right concept. Major considerations in the process and facility selection for a petroleum field, such as shore distance, drilling and well intervention, topside weight, utilities, accessibility, regional influences, financial and HSE considerations, and particularly water depth and well count, as well as their influences on the final decision have also been explored.
The review also introduces common components of a subsea completion system such as wellheads, manifolds, flowlines and risers, connection systems, control systems and umbilicals, installation tooling, and then it makes a comparison between different types of Xmas trees as well as various well arrangements. Finally, the paper summarizes the subsea development phases for establishing the right concept.
Kinetic, Equilibrium and Thermodynamic studies on the removal of Cr(VI) by activated carbon prepared from Cajanus Cajan(L) Milsp seed shell
Authors: Thamilarasu P. , Kumar G. , Tamilarasan R. , Sivakumar V. , Karunakaran K. 
Published: January 2012

Kinetic, Equilibrium and Thermodynamic studies on the removal of Cr(VI) by activated carbon prepared from Cajanus Cajan(L) Milsp seed shell
This paper presents the feasibility of the removal of hexavalent chromium ions from aqueous solutions by using activated carbon prepared from Cajanus Cajan(L) Milsp. It was carbonized and activated by treating it with concentrated sulfuric acid followed by heating for 5 h at 500°C. Batch adsorption experiments were carried out as a function of pH, contact time, initial concentration of the adsorbate, adsorbent dosage and temperature. The experimental data fitted well to the Freundlich isotherm. The thermodynamic parameters such as ΔH°, ΔS°, and ΔG° were calculated, which indicated that the adsorption was spontaneous and endothermic in nature. The adsorbent used in this study was characterized by FT-IR and SEM before and after the adsorption of metal ions. The results indicate that Cajanus Cajan(L) Milsp can be employed as a low cost alternative and commercial adsorbents in the removal of chromium (VI) from water and waste water.