bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exploratory Drilling in Severely Ballooning Formation - Use of Best Drilling Practices and Real Time Monitoring for Low Cost Mitigation
Authors: Golwalkar A. , Lang C. M. , Doodraj S. , Singh A. K. , Manoranjan K. , Pandita A. 
Published: November 2016

Abstract
Wellbore ballooning (or wellbore breathing) is a pertinent drilling issue in exploration wells where the formation lithology, geo-mechanics, pore pressure and fracture pressure regime is not fully understood. This phenomenon is generally observed in formations with micro-fractures. While the pumps are on the ECD is just sufficient to open up the natural micro-fractures allowing the mud to enter the formation. As the pumps are switched off the dynamic pressure effect is lost and the static mud weight is insufficient to keep the fracture open, resulting in the mud lost in the formation to flow-back as the fracture closes. A flow back of mud is observed on the surface with pumps off, which can be misinterpreted as wellbore influx or kick.
Misinterpreting a wellbore ballooning phenomenon as a well kick can lead to the application of standard well control procedure which can aggravate the problem and may have severe implications even to the extent of well failing to meet its objective and being prematurely abandoned.
This paper presents case studies of two wells, viz. NJ North East-1 and Raag Deep Main-1, drilled by the operator in the same block. Severe ballooning was observed in the first well wherein delayed identification of the phenomenon resulted in high NPT and consequential cost impact. The lessons learnt from this experience were implemented in the second well with similar ballooning issues, along with close real-time well monitoring while drilling resulting in smooth drilling operation and successful achievement of objectives as per plan This paper also summarizes suitable in-field drilling practices to be adopted and implemented to mitigate wellbore ballooning, which can be a low-cost alternative to expensive technologies used to counter this phenomenon.
Experimental Study on Injection Strategy of CO2 Near-Miscible Flooding in Low Permeability Reservoirs with High Water Cut
Authors: Chen Hao , Yang Shenglai , Liu Jianchun , Zhang Xiansong , Mei Yuan , Li Xiaofeng , Li Ying 
Published: November 2016

AbstractLack of gas source and poor physical properties of oil are two key problems for the application limitation of CO2 miscible flooding in China. However, in Jilin oilfield, the discovery of natural gas reservoir with different CO2 content (5%-98%) make it possible, especially for some low permeability blocks. MMP determined by slim tube test is 23.5MPa. Reservoir pressures after prolonged waterflood development are maintained at 23 MPa to 24.5 MPa. Thus, CO2 near miscible flooding for these oilfields is of great potential. Advanced CO2 injection is proposed for the undeveloped blocks and WAG is proposed for the high water cut blocks.Long core (~1m) test shows that CO2 injection before oil production can ease the fast decline of reservoir pressure for this low permeability reservoir. Oil and CO2 has more time to contact then miscibility can be fully developed, fingering improved and oil damage of depleted development can be avoided. Recovery incremental is about 6.7%.In addition, injection rate, injection opportunity, injection pressure, water gas ratio (WGR), water cut, gas oil ratio and oil recovery were all considered to optimize the parameters of WAG in waterflooded reservoirs with different water cut (30%, 50%, 75%, and 90%). Results show that the optimum WGR is 1:2, and the optimum gas slug is 0.1 PV. Channeling and bypassing were concluded to be the main reason for the early breakthrough and low oil recovery considering the low transmissibility. However, slow gas injection rates, may fail to maintain pressures and oil rates. Thus, the optimum injection rate is 0.05 cc/min for both water and CO2. Also, it was found that the earlier the WAG conducted, the faster the water cut and oil production response, and the more obvious the water cut decline and oil recovery increase. Results show that more than ~30 % of the residual oil after water flooding could be recovered, which indicates that CO2 near miscible flooding, including advanced CO2 flooding and WAG, could be feasible in some blocks of this low permeability reservoir.The results of this study should contribute to our understanding of the mechanisms and injection strategy of CO2 near miscible flooding in water drive reservoirs and support the ongoing research, development and application of CO2 tertiary oil recovery process in Jilin Oilfield.
Multi-Attributes Analysis and Neural Network: A New Approach of Reservoir Characterisation in Thap Raet and Greater Sirikit East, Phitsanulok Basin
Authors: Suwatjanapornpong Supannika , Jaruwattanasakul Chalong , Kreeprasertkul Kritti , Suwanruji Padsakorn 
Published: November 2016

Abstract
Thap Reat (TRT) and Greater Sirikit East (GSE) are mature oil fields located in the Phitsanulok Basin, in central Thailand. Structural play types are the main contributors to maintain high production of this field. Nevertheless, stratigraphic play types have become more interesting in these to identify new opportunities in undrilled areas. The major challenge of these stratigraphic plays is understanding the depositional model and facies distribution, which with conventional techniques may not be able to properly portray the subsurface framework. The combination of statistical methods along with multi-seismic attributes analysis will help characterize the reservoir complexity.
This study aims to predict reservoir properties by utilizing a combination of well and seismic data through statistical analysis. There are three main steps in this study. Firstly, several seismic attributes are derived from seismic data and then, using statistical methods select the best group of attributes. After that, the neural network algorithm is used to improve the correlation between well log and seismic attribute through a non-linear relationship. Finally, the result has to be validated by correlation error and then applied to a seismic cube in order to predict reservoir properties from multi-attributes.
From available data, there are many types of log can be used in prediction such as P-wave velocity and porosity. Each predicted log shows a good relationship between seismic traces and seismic attributes. This study will use porosity logs to predict porosity from the seismic cube. To get the best result, the accuracy of synthetic seismogram is very important to define the analysis window. After the results of multi-attribute analyses are evaluated by an automated blind test, the operator is created internally and then applied to an entire seismic cube. Nevertheless, not only are the multi-attributes used to predict the reservoir characteristics, but also a neural network is able to improve the correlation value by its non-linear relationship. As a consequence, the new operator updates the prediction in 3D volume. From geological interpretation of the results, the stratigraphic features are better illustrated and thin reservoir trends can be predicted. Finally, it can be concluded that the statistical method in combination with seismic data works well to characterize thin reservoirs in a mature oil field. Additionally, from a statistical viewpoint, the higher accuracy of valid input data leads to a more reliable outcome.
The study supports depositional models serving stratigraphic play exploration. The outcomes can be used in the further work in both exploration and development. Predicted reservoir connectivity can be used to support secondary and tertiary recovery. Moreover, it is more efficient and decreases time-consuming conventional attribute analysis.
Predicting the Location of Multiple Volcanic Eruption Vents for Resolving Facies Heterogeneity and Distribution Patterns within Extremely Challenging Gas-Bearing Underwater Volcanic Deposits of Japan
Authors: Kar S. , Kodaira C. , Irie S. , Li S. , Morelli C. , Gong H. 
Published: November 2016

Abstract
The current study was carried out in one of the most economically viable gas-bearing reservoirs in Japan, the Minami-Nagaoka volcanic field, located to the southwest of Nagaoka. Petroleum deposits occur in deep-seated underwater volcanic rocks of Miocene age, and these deposits contribute significant amount of Japan's total natural gas production. Because of the steep rise in domestic gas demand, re-examination of the existing data sets was performed to understand the geological reason for the extreme lateral facies variation, the complex facies distribution pattern, and production uncertainties. The study revealed a very interesting geological phenomenon of multiple eruption vents that is responsible for the complex facies association and distribution pattern within the study area.
A robust workflow was designed through maximizing utilization of existing high-resolution datasets to solve the current challenges in the field. At the beginning of the workflow, different complex underwater volcanic facies were recognized in image, core, and log data. After volcanic facies reconstruction in each well, facies associations and their distribution pattern across wells were visualized. Finally, using background geological knowledge and well-based facies identification and correlation, a model with multiple volcanic eruption vents was conceptualized within the study area from north to south. In addition, the probable location of different drilled wells relative to the location of the multiple volcanic vents was defined based on the facies assemblages of each well.
The present work demonstrates a unique way to conceptualize and model the paleovolcanic eruption events within a volcanic field. Understanding the paleovolcanic eruption model is key for proper understanding of the facies distribution pattern and facies variation across wells and for finding the best drilling location for hydrocarbon exploration wells. It was observed that the facies with a high amount of lava are located close to the volcanic vent, and wells with a higher amount of brecciated facies are located farther from the volcanic vent. Another type of facies, which is unique for underwater volcanism, is the hyaloclastite (glassy type) facies; this facies is located towards the margin of the volcanic vents. In addition, lateral facies variation was clearly understood after visualizing the eruption model, which was no possible prior to the present study.
The current workflow demonstrates a novel approach for better understanding the paleogeological condition for a unique type of gas-bearing submarine volcanic reservoir, which is a very rare example in the present oil and gas industry. The technique in this work represents a new way of looking high-resolution well data for geological modeling and evaluation of any volcanic field.
Towards a Better Selection of Foamers for the Deliquification of Mature Gas Wells
Authors: Omrani P. Shoeibi , Shukla R. K. , Vercauteren F. , Nennie E. 
Published: November 2016

Abstract
In mature gas wells which are suffering from liquid loading, foamer injection is employed to mitigate the liquid loading and increase the stable gas production. Evaluation of the foamers performance and their chemical stability prior to their injection in the wells is of great importance. For this purpose, laboratory tests are performed to give an indication on the foamers performance. In this study, we focus on the effect of hydrocarbon fractions (condensate/brine ratio) and temperature (up to 120 °C) on the foamer performance in laboratory tests. A modified version of the Bikerman gas sparging setup was designed to allow for tests at higher pressures (up to 15 barg) and temperatures (up to 150 °C), compared to the currently available test setups. Three tests were performed to quantify the foamer performance; foam buildup, collapse and liquid carryover tests. The results indicated that higher hydrocarbon fraction significantly reduces the foam formation rate and liquid unloading capabilities. The current work highlights the importance of using a representative brine-hydrocarbon ratio for foamer evaluation tests. Additionally, on the effect of temperature, three different foamers were studied and the results showed a significant negative influence of high temperature on the foamer performance. It was observed that the effect of temperature on foamer performance is surfactant dependent. Therefore, it is essential to evaluate foamers in the laboratory tests at the temperatures as close as possible to the field (downhole) temperature.
Estimation of Fluid-Fluid Contact and the Transition Zone: A Case Study of Low Contrast Resistivity Zone
Authors: Akbar M. N. Ali , Permadi P. 
Published: November 2016

Abstract
Determination of a fluid-fluid contact and the transition zone is a crucial problem in formations having a low contrast resistivity (LCR) characteristic. High reservoir heterogeneity even makes a serious problem when the contact is not encountered in the existing wells drilled. Improper use of capillary pressure data may lead to severe errors in estimating both the contact and the transition zone.
This paper presents a technique to determine a fluid-fluid contact by maximizing and integrating geological and engineering data available such as well logs, routine and special core analysis (SCAL), and flow test data. Integration of all the data leads to establishing rock types along the interval of interest and developing the corresponding capillary pressure data needed. Establishment of rock types is shown to be of importance because SCAL data are rock type dependent. Flow test data and relative permeability ratio data are used to determine water saturation at the tested interval.
Two well cases of a LCR zone are considered in this study. All the data needed are available, except that capillary pressure data are limited. The rock type model based on the core analysis data available enables us to develop additional capillary pressure curves as needed. Combination of log responses and routine core data are used to predict permeability. The rock types are then distributed in the well within the tested zone. The oil-water contact (OWC) estimated for each of the zones by applying the technique proposed is significantly deeper than that previously determined using resistivity logs. The water saturation distribution within the transition zone is controlled by the distribution of rock types. When the previous corresponding OWC in each zone is used, it is shown that the calculated Water Cut much higher than the actual data. This demonstrates that the electric log-based OWC is too pessimistic.
In conclusion, the LCR zone under the study needs an integrated solution. The proposed technique offers a theoretically sound solution for estimating a fluid-fluid contact and water saturation distribution in the transition zone. It can be applied to common problems of fluid-fluid contact estimation. A procedure to overcome limited SCAL data is provided.
CCS- A Bitter Past or a Prospective Future
Authors: Khan S. , Ali S. F. , Athar K. S. 
Published: November 2016

Abstract
Carbon Capture and Storage (CCS) is indeed a very effective technology in reducing the CO2 concentrations from the atmosphere and possesses massive potential for mitigating climate change. Over the years CCS processes has evolved, however, it is still believed to be in initial phase and appears as a new idea to many under developed countries. Today CCS appears as the only applicable solution to reduce Gigatonnes (Gt) CO2 emissions besides burning the fossil fuels for energy. The application, however, is not as straightforward as it appears. The high costs and potential risks associated leaves the vision of mitigating climate change through CCS under obscurity, thereby, making the future of CCS a bit vague.
This paper aims to project the near future of CCS by the analysis of present CCS prospects, CO2 capturing and storage processes, risks and problems associated, and more importantly the economics encompassing a CCS project. The paper begins with the brief overview of Carbon Capture and Storage (CCS), followed by a comparison of different capturing processes, storage mechanisms, potential problems and risk complications; a comparison of renewables in contrast with CCS is provided. Lastly, the economics and costs of present CCS prospects in different parts of world are discussed. All work is done to make future inferences about CCS, how this evolving technology can be made economically feasible also, and what will be the impacts and consequences on the climate change (increasing GHG concentrations) had no government, public and private sectors consideration been given to CCS, and will the environment be ever safe without CCS.
Evaluation of Three Phase Relative Permeability Models for Simulating Immiscible WAG Injection in Carbonate Rocks
Authors: Al-Nuaimi Latifa , Shahrokhi Omid , Sohrabi Mehran 
Published: November 2016

Abstract
Three phase relative permeability models are used widely by reservoir engineers to investigate the performance of petroleum reservoirs, in particular, for designing gas injection strategy or WAG injection projects. However, there are concerns about the validity of the existing models and the reliability of predictions made by these models.
In this paper, we have assessed the performance of some of these models for WAG injection in carbonate rocks by comparing the prediction of the models with the results of coreflood experiments performed under reservoir temperature and pressure.
Two phase relative permeability results were obtain from history matching the experimental data by using our in-house history matching software. The estimated gas/oil and water/oil relative permeability curves were then used to simulate the results of immiscible gas and water injection under different injection strategies using different three-phase kr models. The results of these simulations were compared with experimental results.
Identifying Deep Sweetspots: Seismically Constrained Reservoir Quality Prediction Offshore Brunei
Authors: Gelinsky Stephan , Kho Sze-Fong , Espejo Irene , Keym Matthias , Näth Jochen , Lehner Beni , Setiana Agus , Esquito Bench , Jäger Günther 
Published: November 2016

Abstract
Prospects below or near shallower producing fields can be economically attractive yet also risky since reservoir presence may be uncertain, reservoir quality can be poor, and high overpressure and temperature can make drilling and logging deeper prospects difficult. Systematic integration of relevant subsurface data from thin section to basin scale allows to seismically identify reservoir presence, and to predict reservoir quality for applicable rock types via burial histories. On an intermediate well log to seismic scale, a predictive rock physics modeling approach links reservoir and seal rock properties to seismic amplitude data to polarize the prospect's geologic ‘probability of success'. Particular challenges in the offshore Brunei study were very fine-grained deposits and non-vertical tectonic stresses associated with compressional settings. Both make porosity predictions that leverage complex burial histories rather than relying on extrapolated depth trends quite challenging - yet the integrated approach remains the best option to identify deep reservoir quality sweetspots that a favorable stress and temperature history may have preserved for certain reservoir rock types in certain locations.
The prolific petroleum system offshore Brunei features two major sediment fairways, the Baram and Champion river systems, and a variety of depositional environments, ranging from high NtG topsets inboard over shallow marine slope settings to deepwater turbidites outboard (Gartrell et al., 2011). Across Brunei Darussalam, the systematic ‘Earth-Model’ study, jointly undertaken by BSP and SDB, defined gross depositional environments (GDE maps) and calibrated a 3D basin model. The study leveraged newly reprocessed Broadband seismic data that over large areas had improved imaging of the subsurface. Complementing this regional geologic evaluation with the goal to assess deep reservoir quality, in the here presented study multiple reservoir and bounding mudrock facies were identified and their composition and texture determined from thin sections. Present day porosity and cement volumes were then calibrated and blind tested with burial histories from the basin model. The reservoir quality calibrations will be applied to predict expected present-day prospect reservoir quality. In parallel, sand and shale acoustic properties were calibrated for applicable rock types to allow for quantitative seismic interpretation of reservoir-seal reflectors and to establish the regional ‘amplitude floor'.
A Case Study on the Shwe Gas Field Development Completion in Myanmar—From Design to Installation
Authors: Park D. , Song I. , Bae Y. , Kikuchi M. , Ling J. P. , West S. , Yap J. , Ridho M. 
Published: November 2016

Abstract
This paper covers the strategies implemented when completing the Shwe gas field in Myanmar. The field, operated by Posco-Daewoo, has been in production since 2013. We present our study and evaluation of the reservoir, integrated completion design, operational challenges, and production performance of the wells.
The project began when Myanmar was subjected to economic sanctions and Myanmar is considered a remote location with quite limited infrastructure, so there were many challenges on the logistics front. The goal of our completion design was to complete the unconsolidated reservoir with either openhole gravel pack (OHGP) or cased hole gravel pack (CHGP), depending on the tendency for water production. The upper completion was designed to optimize gas production. Permanent downhole gauges (PDHG) were installed to monitor the reservoir pressure and temperature.
As part of the development program, eight gas wells and one condensate disposal well were drilled and completed from 2013 to 2015. –Logistics and preparation, key contributors to the success of these installations, were supported from Singapore with a limited transit time to the platform, which meant that turnaround time was closely monitored to meet delivery each time.–The lower completion project in the 9 5/8-in casing consisted of four OHGP wells and four CHGP wells. Screen type and size, and gravel type and size were determined using particle size distribution studies with core samples and software simulation. Findings were then further verified with extensive lab testing.–To achieve minimal skin and damage for the gravel pack (GP) carrier fluid, a nonpolymer fluid was used for CHGP and OHGP. Although a breaker was incorporated into the carrier fluid for OHGP, a filtercake breaker was pumped afterward for maximum cleanup. As for CHGP, the wells were acidized prior to gravel packing. Breakers for the carrier fluid were displaced pre- and post-GP.–For the upper completion, five wells with 7-in production string and three wells with 5.5-in production string were completed. After landing the completion string, a formation isolation valve (FIV) was cycled open, followed by well testing. The subsequent pressure matching we performed confirmed that minimal skin and damage were achieved.–We achieved and exceeded all the objectives set for the campaign in terms of HSE performance, operational efficiency, production rate, and sand-free production.