bluuebunny/crossref_metadata_2025_split huggingface dataset:
On the Importance of the Quality of Conceptual and Engineering Design of Marine Structures used in the Development of the Russian Arctic Offshore Petroleum Resources
Authors: Zolotukhin A. , Papusha A. 
Published: September 2014

Summary
It is known that one of the characteristic features of operating facilities in marine oil and gas fields in the Russian Arctic seas is their interaction with ice formations (icebergs, hummocks, their fragments, ridges, etc.). This kind of exposure is accompanied by plowing (gouging) the seabed, leading to significant damages of its surface in the form of grooves and plowmarks. Generated static and dynamic loads on the infrastructure facilities such as artificial islands, gravity and fixed platforms, subsea pipelines, elements of port facilities etc. can pose a real threat to their operation.
The paper presents different, in terms of hardware implementation, methods of investigation of the following interactions: of artificial island built on extremely shallow Arctic shelf with sedimentary rocks, including permafrost rocks;of subsea gas pipeline with ice formations (fields) in Arctic conditions.
The first part of the report covers the following issues: construction of artificial gravel island on extremely shallow Arctic shelf with seabed sediments;strength and stability of the seabed rocks, taking into account the permafrost substrate under the island;permafrost thawing due to operation of the Arctic field using an artificial island, and includes the relevant design calculations.
The second part deals with the analysis of the stability and strength of large diameter subsea gas pipeline, laid in sedimentary rocks of the shallow Arctic shelf while seabed is plowed by hummock or iceberg keel and keel collides with the pipeline body. Here, we also consider the possibility of underwater pipeline "sweep" by hummock or iceberg.
The paper also describes the basic design decisions, such as artificial islands and underwater gas pipelines, safety of which is confirmed by analysis of exposure to ice formations. As a result of our studies, a map of the Russian Arctic offshore area is plotted with marked zones characterized by increased risk of exposure of the studied facilities to potential hazards. This map takes into account the depths of the seas of the North-Western Russian Arctic zone, publicly available data of the Arctic and Antarctic Institute (AANII), as well as publications of researchers in the region.
We note that the developed method for assessing the strength and stability of underwater gas pipelines in junction areas of onshore and offshore segments, as well as the stability of artificial islands on the shallow Arctic shelf may be used as the basis for developing regulations to design oil and gas infrastructure facilities in the Arctic.
Integration of Methods for Forecasting and Identification of Rock Faults and Fracture Zones to Reduce Risks at their Crossover during Extended Reach Drilling of Long Horizontal Sections (6000 m) in Yuri Korchagin Field
Authors: Golenkin M. , Shtun A. , Khaliullov I. , Sadykov L. , Zakharov I. 
Published: September 2014

Abstract
This article is based on results of drilling wells in Yuri Korchagin field. Interpretation of the obtained data derived the conclusions that will help to stake future wells in better geological conditions and minimize risks during construction of wells.
Drilling Record ERD Wells at Yamal Region
Authors: Glebov Evgeny , Shokarev Ivan , Boroday Aleksey , Grigoryev Maxim , Gulov Artur , Zhludov Aleksey , Chetverikov Dmitry , Dymov Sergey , Dobrokhleb Pavel , Ablaev Anton , Yakovlev Alexander , Petrakov Yuri , Sobolev Aleksey , Korelsky Evgeny , Zadvornov Dmitry , Zavarygin Sergey , Sulimov Dmitry , Kuzakov Vitaly , Alexandrova Anna , Perkshev Dmitry , Makhambetov Amangeldy , Urmantseva Lena , Leontyev Dmitry , Belyaev Aleksey , Shirshov Anton , Shakirov Eduard , Kovalev Alexey , Gainullin Marat 
Published: September 2014

Abstract
The interaction of NOVATEK, Investgeoservice (IGS) and Schlumberger allowed to deliver 2 complex extended reach wells (ERD), including the longest ever drilled in Russian mainland, well number 373, in the Yurkharovskoye field located in Arctic Yamal peninsula, as part of the offshore development plan from onshore locations.
A geomechanical model was developed to address the main challenges, including optimum equivalent circulating density window and drilling regimes for wellbore quality and stability.
Drilling & Measurements key technologies, multipole sonic-while-drilling, latest high-speed telemetry service, multifunction logging-while drilling technologies were used for real time Geomechanics service to prevent costly wellbore stability issues. In addition the combination of rotary steerable technology with customized polycrystalline diamond compact bits and drilling fluid system, delivered superior drilling performance, resulting in high performed drilling of these complex wells.
Positive experience in the construction of these ERD wells, gives grounds to include options for developing the region, similar wells in the planning stage of various development scenarios.
This article devoted to the description of technologies and solutions that have been used for the construction of these wells.
Synergizing Managed Pressure Drilling, Pore Pressure Prediction and In-Line Gas Chromatography Technologies for Enhanced Formation Evaluation of Exploration Wells
Authors: Norcross Dean , Fisher Kevin , Morrison Alan , Wuest Chad Henry , Bamborough Edward , Toralde Julmar Shaun 
Published: September 2014

Abstract
Exploration wells normally employ a gamut of advanced well construction and formation evaluation technologies to be able to ensure the success of the operation. Among these technologies are managed pressure drilling (MPD), pore pressure prediction (PPP) and in-line gas chromatography (IGC). However, since these technologies normally belongs with different end users, with PPP and IGC under the purview of the geologists and MPD with the drilling department, the full utilization of the combined capabilities of these technologies have yet to be realized.
MPD, PPP and IGC techniques can be combined to enhance and increase the information collected about the formations being drilled. This paper describes how the advanced flow detection capabilities of MPD can be utilized to safely allow for the collection of data required for PPP purposes and even enable verification of predicted values and the collection of additional pore pressure information. It also details how IGC in tandem with MPD can further enhance data collection by enabling full characterization of the events detected by the MPD system, instead of losing the same at the mud – gas separator, whenever flow is routed there as a precaution. Conversely, this also provides validation for the events detected by the MPD equipment thereby minimizing the chances of having false alarms with the system.
When synergized, MPD, PPP and IGC technologies have the potential to greatly enhance the characterization and evaluation of wells, especially those drilled for exploration purposes.
Successful Application of Diagnostic Interventions for Well Revival: A Case Study
Authors: Singhal JOY , Goenka Sharad Kumar , Kothiyal Manish Dutt , Parasher Arunabh 
Published: September 2014

Abstract
Field X in India has been developed as an onshore field wherein wells are drilled in shallow reservoir. There are approximately 110 oil producers and 60 water injectors in this field. To mitigate sand production, wells have been completed with standalone screens (including conventional, SSD & ICD). Crude of the reservoir is high in wax content with pour point at 50 oC.
This paper highlights a case study on one of the oil producer X-A which was drilled & completed as 4-1/2” standalone screen completions to ensure selective production from various sands. Post completion, in all the subsequent rigless interventions conducted in the well X-A, an obstruction was observed against one of the Screen SSD. Initially a scale build up or a sand bridge was suspected at the obstruction depth, but well bore clean out with coiled tubing intervention failed to clear it off and pass through. Also, communication was suspected between tubing & tubing-production casing annulus. In view of above, the well was kept shut-in for more than a year.
This well, therefore became a critical case wherein application of Downhole Video Camera detected the potential leak in the tubing above the production packer and buckling of lower completion. Further, the Production Logging Survey confirmed the leak in the tubing. Based on the above field observations a CT conveyed Taper milling was conducted to clear off the obstruction post which work-over was conducted for upper completion.
This paper details the collaborative approach of diagnostic and troubleshooting interventions planned in the well X-A, challenges involved in the same and lessons learnt during the whole operation, which finally helped in bringing the well online successfully and affordably, avoiding numerous time and money consuming interventions which could have been carried out in absence of detailed root cause analysis of the problem.
Introduction
Well X-A is a deviated oil producer in field X. Post completion of the well, during attempts to flow back the well, an obstruction was observed around one of the screen SSDs which prevented any well intervention to bring the lower zones on production. Several conventional attempts were made by slickline & coiled tubing to clear the obstruction but all interventions were in vain and no success was observed. In addition to failure to clear the obstruction, these conventional methods also failed to provide clear indication regarding the cause & type of obstruction. Further sections of the paper highlight the well investigation with Downhole Video Camera technology and then clearance of obstruction with Coiled Tubing conveyed Thru-Tubing Tapered Mill.
Increasing Sales Gas Output from Glycol Dehydration Plants
Authors: Dreher Trina , Cavill Michael , Geard Adam 
Published: September 2014

Abstract
Natural gas contains significant amounts of water that must be removed. A common way to dehydrate gas to low water levels is via a liquid desiccant such as tri-ethylene glycol (TEG) and the use of stripping gas in the regeneration system.
The patented GLYNOXX® recycle stripping gas process offers a solution to obtaining enhanced gas dehydration without wasting valuable product. In this process a small amount of stripping gas is introduced into the stripping column, which once it passes through the column is cooled to condense and separate the majority of water. The stripping gas is then recycled to the stripping column via a blower. The stripping gas used is preferably flash gas, although if sufficient quantities are not available then fuel gas may be used. Regardless of the type of stripping gas employed, the recycle process ensures that only very small make-up quantities are required on a continual basis thereby decreasing the amount of fuel gas consumed during operation. An additional advantage of the GLYNOXX process is that it reduces the amount of gas vented from a TEG dehydration plant thereby reducing the carbon emissions liability of the plant.
The GLYNOXX process may be integrated into a new TEG dehydration plant or retrofitted to an existing TEG dehydration plant. This paper details the GLYNOXX design and how it is integrated into both new and existing plants. It then compares the operation of an existing TEG dehydration plant that employs standard stripping gas operation with that of the GLYNOXX process following a retrofit, including the required plant modifications. A simplified economic analysis is presented for a retrofitted GLYNOXX process to illustrate the significant advantages of the technology for TEG dehydration plant operators.
HPHT Hydraulic Fracturing Proving Late Jurassic Cretaceous Petroleum System Reserved at Krishna Godavari Basin
Authors: Barasia Ankur , Sharma Amit , Shado Olushola , Deshpande Vaibhav , Srivastav Saurabh , Singh Mukund Murari , Tiwari Shobhit , Ranjan Vishal , Ranjan Amit 
Published: September 2014

Abstract
Between 2010 to 2013, three onshore appraisals well are drilled in the southern part of KG Basin, aiming to appraise economical potential of oil reserved from Late Jurassic Cretaceous petroleum system. Some of the major inherent challenges of this region are to complete and test the wells with very tight deep sands and HPHT operations.
The target reservoir consists of two distinct pay zones, the lower part is G formation which consists mainly siltstones, and the upper part is cleaner R sandstone. Total thickness of primary target zone of interest is more than 200 m with average permeability of less than 0.1 mD. Open hole log indicated water saturation in G formation to range between 20% to 60% while in R formation saturation range was between 40 to 70%. Initial exploratory test showed no significant flow of hydrocarbon therefore hydraulic fracturing program was proposed and planned as the enabler to facilitate production at economic rates from these reservoirs.
Detailed petro-physical and geo-mechanical formation evaluation with Mechanical Earth Modeling, reservoir evaluation using Injection Fall off test and fracture height estimation using Planar 3D models are some of the tools used to ensure a successful stimulation job across a 200 m thick G formation which appeared to have no significant stress contrasts to confine individual fracture treatments. The hydraulic fracturing project workflow includes selecting right perforation strategy, optimizing number of fracturing treatment and minimizing fracture interference. Proper data interpretation, meticulous planning and detailed engineering analyses and design overcome these challenges, which lead to successful hydraulic fracturing completion of all the wells in the campaign with encouraging well production test results and thus confirming the presence and commerciality of hydrocarbons in this field.
This paper details the technical analysis and engineering workflow used as tools for a successful hydraulic fracturing of G and R formation. Design, Execution and Evaluation process used during hydraulic fracturing is also discussed. In the end, lessons learned and recommended workflow to explore similar reservoir in the future have been captured.
Preventing String Integrity Failure in Production and Stimulation for High Temperature Wells
Authors: Aditya Gama Hafizh , Subiantoro Edy 
Published: September 2014

Abstract
String integrity is essential for successful production and stimulation.
With production, string integrity means pressure integrity of packers and sliding-sleeve-doors commonly used to isolate target production zones. With hydraulic-fracture stimulation, frac-string integrity is mostly concerned with the burst pressure of the string, packer load and string friction, which depend on fluid rate and pump pressure.
In high-temperature wells, things get more complex. High rate producers heat the production string far above the normal gradient temperature, and so it expands. With frac strings, the opposite occurs. Injected water cools the string far below the normal gradient temperature, and so it shrinks. Both situations create additional string integrity issues.
In 2008, EMP Malacca Strait drilled and completed (as selective singles) three infill wells in Kurau, a mature oil field in Sumatra, Indonesia. Later, when changing ones, the completion string was found to be buckled. An impression Block showed an obstruction inside the tubing. This zone could not be changed.
In the same year, we performed our first hydraulic-fracture-stimulation campaign in the Kuat oil field, of sandstone reservoirs at 320 degF. During the first job, the frac string failed during the data-frac, as seen by the sudden increase in annulus pressure. We suspected the packer unset due to high shear load from frac-string thermal shrinkage.
Both these string failures occurred, despite standard shrinkage calculation suggesting there should be no issues.
The paper investigates elongation and shrinkage of production and frac strings using a finite difference-mathematical model. The study found a much higher thermal expansion factor than from a standard calculation, and so we started to use expansion joints for both selective completions and for fracture-stimulation campaigns.
Since this time, we have suffered no further string failures.
Application of Velocity-Dependent Relative Permeability for Modeling Gas-Condensate Reservoirs: Field Example
Authors: Tani Kengo , Yamada Tatsuya , Ikeda Shuichiro 
Published: September 2014

Abstract
In recent years there has been a growing interest in accurately modelling the condensate banking phenomena in gas-condensate reservoirs to better predict production performances. The velocity-dependent relative permeability (VDRP) concept is one of the methodologies to replicate well production performance reflecting both condensate banking phenomena and velocity effect in gas-condensate reservoirs. In this paper, we present the result of a fine-scale compositional reservoir simulation study by introducing VDRP model validated against the actual field production data from a gas-condensate reservoir called S-Tuff Formation in Minami-Nagaoka Gas Field in Japan.
A comprehensive data acquisition program was implemented during the long-term production test of the S-Tuff formation to enable the detailed evaluation of production performance and near-wellbore fluid behavior in the reservoir. The program included the measurements of flowing and shut-in bottomhole pressures, surface flow data and fluid sampling. The ultimate objective was to accurately predict the field production performance by an established reservoir simulation model through history matching.
The fine-scale compositional reservoir simulation study showed that VDRP model was required to obtain reasonable match with production data, including BHPs and GOR, whilst it was not achieved by the model with conventional gas-oil relative permeability curves because the simulated FBHP fell far below the observed data when the FBHP was below dewpoint. Hence, the study suggested that improvement of gas-oil relative permeability by velocity effect occurred during production. It was also shown that the well productivity impairment due to condensate banking in VDRP model was not as severe as in the case where the conventional fixed gas-oil relative permeability was used.
In this study, the VDRP concept was adopted to evaluate the impact of condensate banking and velocity effect, and its methodology was validated using the actual field production data and its history matching. This study will contribute further improvement of performance prediction for similar gas-condensate reservoirs.
Formation Tester Optimization for the XiHu Basin: Observations and Case Studies from the East China Sea
Authors: Shi Rongfu , Wang Jianping , Liu Daneng , Zhang Guodong , Tellapaneni Prasanna , ChengGang Xian , Chen Jichao , Yu Yin Hua 
Published: September 2014

Abstract
In recent years, low-porosity and -permeability gas reservoirs have become an important exploration target for the industry in general, and the China National Oil Company (CNOOC), Shanghai branch, in particular. Formation evaluation of these resources is inherently challenging, and the application of formation testers has become an integral part of the evaluation workflow to address these challenges.
The XiHu basin, located offshore China in the East China Sea, is a frontier exploration area for CNOOC Shanghai branch. Drilling safety in the XiHu basin is a concern owing to the intermediate high-pressure sands and overlying coals. Drilling with high overbalance and long openhole sections to mitigate these challenges has in turn caused problems for the formation testing program that are manifested as elevated pressures and long sampling times.
The optimization of formation testing began with the statistical analysis of historical data to identify trends in pressure measurement and sampling. This analysis clearly indicated that continuous filtrate invasion and water slumping processes contributed significantly to the long sampling times and apparent elevated pressures observed. Therefore, these mechanisms were studied by modeling the invasion process quantitatively using a finite-difference simulator. After matching the simulated pressures with measured pressures in a candidate well, the effect of these invasion mechanisms on the formation testing program and ways to mitigate them was investigated.
Our study shows that the invasion profile in these reservoirs is different from the classic invasion profile. The classic model shows minimal invasion at the top of the sand, but we observed the longest cleanup times were generally at the top of the reservoir. Using realistic physical and drilling parameters, we demonstrate that invasion effects are often more complicated than the classic model.
Optimized tool selection and testing processes have been proposed to mitigate the effects of the invasion processes. The applicability of new technology in these challenging environments was also studied and demonstrated through case studies in which an overall efficiency improvement in the formation testing program was observed.
Gas Turbine Power Generation Utilising Low and Variable Quality Gas Fuels in Dry Low Emissions Combustion Systems
Authors: Welch Michael 
Published: September 2014

Abstract
Since the late 1980s, environmental concerns over pollutants created during the combustion process have driven gas turbine manufacturers to develop combustion systems that create lower and lower emissions of nitrous oxides (NOx), carbon monoxide (CO) and unburned hydrocarbons (UHC). To meet this challenge, manufacturers developed Dry Low Emissions (DLE) or Dry Low NOx (DLN) combustion systems. Primarily employed initially in industrial applications or utility power plant using pipeline quality natural gas as the main fuel, DLE became quickly established and is now a well-proven technology with thousands of units installed and tens of millions of operating hours experience gained. Some manufacturers now only offer DLE combustion systems on some gas turbine models, such is the confidence in this technology.
Upstream Oil & Gas operators face challenges that industrial users and utility companies don't: the gas fuel available is in most cases not ‘pipeline quality’, containing varying amounts of contaminants such as inert gases or higher hydrocarbon species; the gas composition can vary depending on both source and time; toxic and corrosive contaminants, such as hydrogen sulphide, might exist within the gas stream; with no connection to an electricity grid system, the gas turbines are required to operate at constantly varying loads to match the power demand of the facilities; and unit reliability is critical to ensure continuous production and revenue generation.
This paper reviews the work undertaken by Siemens Industrial Turbomachinery on their range of gas turbines between 5MW and 50MW in power output to characterize the capabilities of the DLE system with respect to the different fuel gas compositions encountered, and the variability of the gas composition, and discusses some examples of installations both in industry and offshore O&G applications where such fuels are used while still meeting the required emission limits and without affecting operability.