bluuebunny/crossref_metadata_2025_split huggingface dataset:
Alternative Vertical Drilling Technology Delivers Premium Performance While Reducing Operating Costs
Authors: Neil P. , Herrington D. 
Published: October 2013

Abstract
Maintaining verticality in today’s challenging drilling applications is of critical concern. The vertical section is increasingly important in anti-collision situations, as well as in extended reach directional wells where weight transfer through tortuous vertical sections can make the difference in calling Target Depth (TD) early of not. Excessive dogleg severity compromises well completion and adds costs that erode the profitability of operations and ultimately production of the well.
To date, a limited number of options have been available, with low cost, low performance systems at one end of the scale and high cost, high performance systems at the other. Every day we are looking at more unconventional reserves and tighter budgets to work within. To align with these goals, we must find a solution that provides the quality performance through a technology that fits today’s fiscal demands as well.
Conventional vertical drilling approaches such as control drilling, drilling with bent housing motors, and rotary steerable systems have notable drawbacks. Poor performance and efficiency on the low end and exorbitant cost on the high end push us to a new solution.
A technology is now commercially available that provides all the performance of the higher cost Rotary Steerable System (RSS) while offering a better economic position for operators. With this new technology, borehole quality no longer has to be sacrificed for cost. The technology is fully autonomous and recent performance data shows that a major operator has utilized this technology for a reduction in costs of over 20% versus conventional technology while providing comparable rates of penetration and borehole quality.
Successful Casing Drilling Experience with Premium Connection for Production Casing Application on a Subsea Well
Authors: Ong G. , Yamaguchi S. , Imai R. 
Published: October 2013

Abstract
This paper discusses the casing design and connection selection process where the first Casing while Drilling (CwD) technology was deployed in a subsea exploration well in the Dampier Sub-Basin, Northwest Shelf offshore Australia to overcome the problematic drilling operations while drilling through the highly porous "Bare Sands" which often led to severe loss circulation. This was the first attempt for the operator to deploy a newly developed Threaded and Coupled (T&C) Type Premium Connection on 9-5/8-in. 47 ppf L80 for production casing application with CwD technology. Hence, the process of identifying and mitigating risks when applying new connection technology in a highly critical application was vetted thoroughly.
It is understood that not all premium connections are suited for such application to meet key selection criteria, such as fatigue performance, torque resistance and being able to maintain gas sealability whilst under severe well load conditions including tension and compression loads after being subjected to severe cyclical bending stress during CwD operation. In order to ensure that the connection survives the continuous abuse during CwD in order to meet the objective of the well, a newly developed T&C connection from VAM® was selected for this challenging application. The connection is characterized by easy field make up, exceptionally high torque resistance, excellent gas sealability which is in compliant with ISO 13679 CAL IV and it comes with superior fatigue resistance attributed to the new and innovative connection technology.
The casing drilling operation was completed from a semi-submersible rig reaching a world record depth at 1,906 m in technical limit time with drilled interval of 1,710 m. The successful deployment of 9-5/8-in. 47ppf L80 with this newly developed premium connection for production casing opens up a new chapter for similar CwD applications in the industry.
Estimation of Porosity, Permeability and Water Saturation in Tight Sandstone Reservoirs Based on Diagenetic Facies Classification Method: Case Studies of Chang 8 Formation in Northwest Ordos Basin
Authors: Hua Yang , Yu-jiang Shi , Shaanxi Xi'an , Liang Xiao , Zhi-qiang Mao , Cheng Feng , Gao-ren Li , Hao-peng Guo , Jin-yu Zhou 
Published: October 2013

Abstract
Porosity, permeability and water saturation cannot be effectively estimated from conventional logs by using the classical methods in tight sandstone reservoirs due to the complicated mineral components, pore structure and strong heterogeneity that caused by the diagenesis in the Chang 8 Formation of northwest Ordos basin, In this paper, based on the difference of diagenetic facies, effective formations are classified into three types, the relationships between conventional density log and core derived porosity, core derived porosity and permeability are established in every type of formation. In the meanwhile, the laboratory resistivity experimental results are also classified based on the diagenetic facies, and the cross plots of porosity and formation factor, water saturation and resistivity index are drawn to obtain the rock resistivity parameters, separately. These results illustrate that for formations with different diagenetic facies, the matrix densities are diverse, the relationships between core derived porosity and permeability are also different, and they contain different rock resistivity parameters. By using the diagenetic facies classification method and chart proposed by Xiao (2012), the effective Chang 8 Formation is classified into three types, and the corresponding models are applied to calculate porosity, permeability and water saturation. Comparisons of estimated porosity, permeability and water saturation by using the proposed techniques and the core derived results illustrate that the proposed techniques are valueable in tight sandstone reservoir parameters evaluation.
Effects of Precipitation Inhibitor on ASP Performance in Carbonate Reservoirs
Authors: Kalwar Shuaib Ahmed , Elraies Khaled A. 
Published: October 2013

Abstract
Field performance of ASP technique has achieved technically successful and economically feasible results for sandstone reservoirs. However, little attention has been given to ASP application in carbonate reservoirs. The main constraint of ASP flooding in carbonate reservoir is the presence of calcite, dolomite and calcium sulfate minerals. These minerals react with the added chemicals to form insoluble salts known as precipitations. Therefore, an Alkaline-Surfactant-Polymer formulation was developed by incorporating acrylic acid as a precipitation inhibitor or protection agent to overcome the precipitation problems caused by reservoir minerals and brine compositions. The performance of the Acrylic Acid (AA) with an ASP formulation was estimated using sodium metaborate and three types of high tolerant surfactants for possible screening. Feasibility of applying AA with ASP formula was demonstrated by comprehensive fluid-fluid and fluid-rock compatibility tests. Static and dynamic experiments were conducted for monitoring precipitations and permeability reduction using a limestone core samples. Hardbrine composition of 59,000 ppm was used to prepare the ASP formulations in the presence and absence of AA. As results, all chemicals including, alkalis, surfactants, and polymers were incompatible with the hardbrine used in this study. Precipitations were generated from the first day of mixing. However, the presence of acrylic acid showed excellent properties in preventing precipitations and all solutions remained clear for 30 days at 80°C. The optimum acid concentration was found to be proportional to alkali concentration using acid to alkali weight ratio of 0.6:1.0. Using the optimum acid to alkali ratio, the permeability reduction caused by precipitations was significantly improved. This might add more advantages to ASP process in which hardbrine water can be used instead of softened water.
Investigation on Corrosion of Insulation Tubing Steel in HTHP Steam and Flue Gas Co-Injected to Enhance Heavy Oil Production
Authors: Zhaoxia Dong , Liguo Zhong , Yicong Tian , Yanchao Wang , Yongtao Sun , Lichang Zhao , Tao Lin , Wenkai Lu , Mingyou Yu 
Published: October 2013

Abstract
Co-injection of steam and flue gas is potentional to improve heavy oil well production. For a typical steam and gas co- generator, the flue gas content is about 10wt%-30wt% in general, the temperature usually ranges from 200℃ to 350℃ (regulated by fuel and water injection rate), and the injection pressure is up to 20MPa. More attention has to be attached to the corrosion of insulation tubing in the HTTP steam and flue gas comprised of CO2, N2 and residue O2. In this work, corrosion performance and inhibition with some additives of the insulation tubing steel in HTHP fluid of steam, CO2, N2 and residue O2 were investigated by weight loss experiment with alloy reactor. The results showed that there are another peak at 200℃ except the corrosion rate peak at 60℃ for CO2 and O2 corrosion, the corrosion rate of steel in co-injected fluid is enhanced at higher temperature. The corrosion principles are related to production of FeCO3 and Fe2O3 under different conditions. At higher temperature, corrosion rate could be reduced with addition of corrosion inhibitor and/or deoxidizer, for example, more than 90% reduction in corrosion rate could be obtained with addition of 2000mg/L selected corrosion inhibitor at 200℃. Additionally, the field testing cases show significant corrosion inhibition of insulation tubing in co- injection of steam and flue gas with addition of corrosion inhibitor.
Integrated Regional Interpretation and New Insight on Petroleum System of South Sumatra Basin, Indonesia
Authors: Carrillat A. , Bora D. , Dubois A. , Kusdiantoro F. , Yudho S. , Wibowo E. , Musri M. , Tobing J. C. , Gomez T. P. , Xue F. , Balasejus D. , McDonald T. D. , Audemard P. 
Published: October 2013

Abstract
South Sumatra Basin is an inverted post-arc Tertiary basin, which has a complex evolution history from late Eocene- Oligocene extension to late Miocene and Pliocene compression. To evaluate the overall basin prospectivity, a regional analysis is conducted at 8 stratigraphic levels from pre-Tertiary unconformity to Pleistocene. An integrated interpretation including more than 1400 2D seismic lines, 4 seismic 3D surveys, and formation evaluation from 80 key wells is used to run the basin analysis. A series of regional seismic transects are defined through key wells and major structural elements to capture the characteristics of structural styles, lithostratigraphy and hydrocarbon distribution across the basin.
Structural restorations unravels the timing of fault activity showing basin rifting until ~23 Ma with main depocenters in Benakat Gully, Limau Graben, Central Palembang and Lematang Depression followed by sagging until 14.6 Ma. The compressive event is recorded from 5 Ma to present day. The buckling of syn-rift sediments suggests shortening expressed by inversion and fault reactivation rather than thrusting. Review of the source rock data, reservoir distribution, hydrocarbon phase and source to reservoir correlation data are evaluated in perspective of the basin configuration in order to select sections for basin modeling. The modeling results show onset of expulsion varying from ~10-15 Ma from Lemat Fm. and Talangakar Fm., and 5 Ma from Telisa Fm. Modeling suggests that Talangakar Fm. reservoirs are completely filled, whereas Lemat Fm. reservoirs are partially filled due to limited lateral and downward migration. Baturaja Fm. reservoirs in proximity to depressions are filled, and partial charge risk away from kitchen area. Most of the hydrocarbon are generated, expelled and accumulated between sedimentation of Lower Palembang Fm. to inversion time (10-5 Ma). The subsequent inversion is likely to have re-migrated hydrocarbon in Talangakar and Baturaja reservoirs along Benakat Gulley and associated fault bound folds.
The Next Generation Petroleum Production Technology; Early Predictive Well Health (WH) Meta Monitoring Tool (ARTAM-WH)
Authors: Goldschmidt Peter , Crawley Charles , Bashirul Haq , Palanisamy Santhosh 
Published: October 2013

Abstract
Maintaining stable operations with high recovery requires routine checking of individual Well Health (WH). A well performing as expected is healthy. It is essential for efficient field operation to detect WH issues early that may reduce overall recovery. An early predictive and WH meta-monitoring tool is highly desirable. Our new approach is designed to provide early identification of existing or developing WH issues - precursors to WH problems if not addressed. ARTAM-WH utilizes in-situ monitoring systems coupled with static data, conducts preliminary analysis and proper cross checking and then notifies engineers/operators. Differentiating this approach is that it is not looking at small data sets but a large palate including both static (the well construct) and dynamic, current performance versus performance expectations. ARTAM-WH provides supporting evidence of WH Issue to the appropriate stakeholder. Notification includes the necessary and sufficient evidence derived from approximate reasoning algorithms combining multiple variables to identify possible issues and testing the WH hypotheses. ARTAM-WH aims to provide early warning signals, including substantiating evidence, to engineers/operators managing large volumes of data generated within monitoring systems; lowering operating costs and expediting the decision- making processes. Reducing time to action; improving operational effectiveness; increasing production due to reductions in unexpected downtime and previous lost profit opportunities being captured. This new approach frees up engineers/operators time to focus on higher priority activities such as developing solutions. Early identification of emerging problems also allows for the ability to handle those problems through normal planning rather than emergency fixes.
Integrated Reservoir Characterisation for Thin Waterflooded Carbonate Oilfield in Oman
Authors: Limin Zhao , Longxin Mu , Haiying Han , Guoliang Zhao , Rui Guo , Jun Wang 
Published: October 2013

Abstract
Reservoir characterization is the most important in building robust geological and simulation models. The improvement in reservoir characterization enhances the understanding of the reservoir heterogeneity and reduces the uncertainties on field development. This can be achieved with better descriptions of reservoir frameworks and properties. D oilfield is located in northwest of Oman and it has been rejuvenated by water injection since 2001 using horizontal well line driving pattern. In this paper, comprehensive reservoir characterizations of thin Early Cretaceous Upper Shuaiba limestone reservoir of this oilfield were carried out based on the current data for guiding the further adjustment plan and achieving better development results.
Horizontal well correlation modes were defined based on the reservoir boundary encountered by the horizontal trajectory to construct the reservoir framework. The interpretation and identification of small faults and fractures were identified based on seismic data, FMI logging, core data and production data. Under the guidance of depositional model, data from horizontal wells has been fully used in combination of pseudo-wells to build the 3D geological model to accurately delineate small faults, reservoir boundaries and property distributions. Based on fracture parameters derived from static and dynamic data, fracture network model and equivalent permeability model have been built constrained by fracture density. The intelligent reservoir characterization provides a reliable geological guidance to ensure the reasonable placements of infill horizontal well trajectories through the reservoir. The real horizontal drilling indicates that the oil reservoir accounts for 90% of the total horizontal section for D oilfield.
Integrated Study of Reservoir Characteristics of a Shale Gas Reservoir: A Case Study from Sichuan Basin of China
Authors: Feng Yang , Zhengfu Ning , Qing Wang , Huiqing Liu , Shidong Zhang , Hongmei Liao 
Published: October 2013

Abstract
The Lower Cambrian Niutitang Formation is an organic-rich siliceous mudrocks which is widely considered to be a potential shale gas reservoir in Sichuan Basin of southwest China. An integrated study was performed to characterize the reservoir characteristics. A series of tests were conducted on core samples including organic geochemistry, mineralogical, petrophysical and mechanical properties. A deep insight into the characterization of pore structure in shale reservoir was analyzed by field emission scanning electron microscope, gas adsorption and high-pressure mercury injection.
The results show that Niutitang Formation shale reservoir has the potential for gas exploration and production due to organic matter rich, moderate porosity and high brittleness. The Niutitang formation is of great thickness and the total organic carbon content ranges from 0.16% to 9.15% with average of 3.56%. The porosity of shale samples is from 1.26% to 9.85% with average of 5.78%, and the pulse permeability of matrix is from 320 nD to 890 nD. The total content of brittle minerals (quartz, feldspar and carbonate) is over 70%, and the formation is characterized as rigid and brittle for high elastic modulus and low Poisson's ratio. There are five types of pores in shale: organic nanopores, pores of clay minerals, intraparticle pores of matrix minerals, intragranular pores from microfossils, and microfractures, and the chief are organic nanopores and pores of clay minerals. Nanopores with pore diameter less than 50nm provide the main pore surface area and pore volume, which indicates they are the main place for hydrocarbon adsorption and storage. These results will provide a basis for further evaluation of the hydrocarbon potential of the Lower Cambrian Niutitang Formation shale in the Sichuan Basin.
Subsea Completion Operated by Longleg Jackup Rig
Authors: Prasetyo Adi 
Published: October 2013

Abstract
Kangean Energy Indonesia (KEI) on behalf of EMP Tbk, JAPEX and Mitsubishi Corporation drilled and completed five (5) Terang high-deliverability gas wells utilizing a Jackup rig in 2011. Terang field, as the Phase-1 of Terang, Sirasun and Batur (TSB) fields’ gas development project was put into production in 2012. TSB fields are located at east of Surabaya and north of Bali Island with the water depth ranging from 300 ft to 750 ft. Terang field is located in the western part of the complex with the water depth of 300 ft.
The challenge of this project was to drill and complete subsea wells by a jackup rig which is equipped with only surface BOP. This is a new endeavor to perform subsea well completion using a jackup rig in Indonesia and finally it is a successful operation to drill and complete the five Terang wells using a long-leg jackup rig. Terang field had been developed by drilling and completing five (5) subsea production wells. Special additional devices were designed and attached to the jackup rig to enable drilling the subsea wells as well as perform batch drilling easily. These are High Pressure (HP) drilling riser and Suspended Texas Deck (STD), which is an additional deck suspended from the rig frame.
The STD was designed and introduced to promote operational safety by supporting safer and practical installation of the surface BOP equipment and also yielded a time-saving by reducing the handling time of HP drilling riser. These added features had proven to reduce operations time when two-well batch-drilling was performed, the rig cantilever could skid in and out with HP drilling riser suspended without breaking out riser connections.
The base cost reduction had been accomplished by utilizing a jackup rig which daily rate is much lower than floater rigs, and the contribution of the additional features of HP drilling riser and STD combination had further optimized the cost. This experience had brought a major breakthrough in drilling operations in Indonesia and KEI believe that the drilling campaign had been executed successfully with a diligent planning and articulated drilling programs.
Biological Effect Monitoring Benzene at Oil Company, What is New?
Authors: Cahyono Dwi , Tjahjono E. W. 
Published: October 2013

Abstract

Background
Benzene is a proven human carcinogen. Exposure to benzene increase incidence of leukemia. The aim of this study is to determine the chromosome breakage of lymphocyte in benzene exposed worker.

Method and Result
The benzene management in TOTAL E&P INDONESIE conducted by performing identification of benzene sources, air monitoring, personal dose measurement, and biological monitoring.
Benzene sources are identified in the location: flotator, pigging, and oil water treatment. Mostof the benzene air concentration reach above Threshold Limit Value (&gt;1 ppm), some are above 250 ppm. Most of personal exposed monitoring and biologic monitoring is below the maximum standard. Risk management was also performed.
The health surveillance in 115 samples shows: 73 samples (63%) have chromosome breakage (banding), 99 (86%) for non- banding. Variables that are statistically significant (p&lt;0.05) are work locations, positions, SPMA in urine, PPE, Respirator use, Vitamin C intake and tea consumption.
A higher breakage of chromosome numbers 3 & 6 found among workers exposed to benzene compared to non/less exposed.

Main Findings and Policy Implication
The finding of this study is the chromosome (3 & 6) breakage among workers exposed to benzene. Despite well recognized benzene effects (leukemia), other possible implications on health can be different for certain populations as chromosome numbers 3 and 6 are associated with endocrine/metabolic and immunological disorders. This is consistent with fact that more than 40 years operation, no leukemia case detected among the workers in TEPI.
Workers health surveillance shall be continued to detect the possible early effects on endocrine/immune systems. Benzene exposed should be further controlled by management benzene exposure (Regular benzene exposure measurement of air ambient and biological monitoring, engineering control of benzene source), antioxidant consumption and behavior of employees in using proper respirator.
Liquid Carbon Dioxide Flooding in Low Temperature Oil Reservoirs
Authors: Moradi B. , Awang M. , Sabil K. M. , Shoushtari M. A. , Moradi P. , Ajdari H. , Shuker M. T. 
Published: October 2013

Abstract
Carbon dioxide injection in oil reservoirs is one of the main improved oil recovery methods; in addition, it is a useful method for the reduction of carbon dioxide in the atmosphere. Carbon dioxide generally exists in supercritical state in hydrocarbon reservoirs that are usually explored, but the temperature of some shallow reservoirs and reservoirs underlying permafrost is below the critical temperature of carbon dioxide which provides a unique opportunity for liquid carbon dioxide storage and the application of a novel enhanced oil recovery method. During this work, a compositional simulation study is conducted by a commercial compositional reservoir simulator to evaluate performance of the liquid carbon dioxide injection in a low temperature heterogeneous reservoir. The results show the oil recovery factor after 24 years of production, during liquid carbon dioxide injection is 14.79 %, which is 3.90 and 8.59 % higher than the water flooding strategy and natural depletion respectively. It also finds that the huge amount of CO2 is stored in the reservoir. This study further shows that the oil recovery increases by increasing the injection pressure and the injection of the liquid carbon dioxide in bottom of the reservoir.