bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study Channel Fracturing for High Production Improvement in a Tight Conglomeratic Sandstone Reservoir
Authors: Kartiyasa Fauzan Agung , Sitaresmi Ratnayu , Wahyuni MG Sri , Oetomo Hari Karyadi , Suandana I. Wayan 
Published: October 2019

Abstract
Channel fracturing becomes more popular as novel method of hydraulic fracturing, with increasingly successful in its implementation. This new method of fracturing, is pulsing proppant into formation instead of just continous pumping as in conventional fracturing. The proppant is mixed with fibrous material, which enables formation to sustain the closing pressure, even with the conductive channel within the fracture; it functions as the pillars of the fracture. The stimulated well is penetrated and producing from poorly sorting conglomeratic reservoir with secondary porosity and muddy micro-porosity; hinderes hydrocarbon flow to reservoir. A well was selected as a pilot well candidate, after reviewing the well test, it reached 230 BOPD. The permeability of the well is 1.78 mD with reservoir pressure of 1188 Psi. Recently, the well produces intermittently 9 to 20 BOPD, assisted by sucker rod pump artificial lift. Initial step is to evaluate the well by using Candidate Selective Factor (CSF), which is based on rock mechanics parameters and stresses within the formation. Afterward, initial design is constructed based on well parameter and its surrounding wells. After the pre-fracturing treatment, which consists of breakdown test, step rate test, and minifrac test, the fracuring operation is re-designed. The re-design includes the special pulsing pumping technique, and then followed by the mainfrac operation. In the actual operation, the proppant was pulsing into formation for eleven times. After channel fracturing, the productivity index of the well increased significantly by 10.3 times with an oil rate of 155 BOPD. Channel Fracturing; a novel technology of hydraulic fracturing; is not only increasingly succesful in its application for giving well production increase, but it also it uses materials that will give less probable of screen out. This method will be implemented in the whole field.
Case Study: Trouble Shooting of Gas Turbine Generator GTG Trips Due to Gas Turbine High Exhaust Temperature Spread While Operating on Liquid Fuel
Authors: Anwar Zeeshan , Manikandan Arumugampillai 
Published: October 2019

Abstract
Gas Turbine Generator (GTG) availability is one of the most critical requirements for any plant production in oil & gas industries. The subject case study provides the information and root cause analysis done on the number of trips happened on a dual fuel Gas Turbine due to high exhaust temperature spread while operating on liquid fuel, that affected plant power production requirements.
An exhaust temperature spread refers to a high differential in temperature readings between the thermocouples placed radially around the exhaust of a gas turbine. Spread indicates the difference between maximum and minimum temperatures recorded by exhaust temperature thermocouples. If spread is allowed without correction, it will result in reduction of residual life of downstream components of the Gas Turbine. The worst exhaust temperature spreads occur when the hottest and coldest spot are nearer i.e. exhaust thermocouple readings are grouped very closely adjacent. Most exhaust temperature spreads are the result of combustion section problems that can lead to premature failure of turbine blade /bucket.
Site is configured gas turbine running on dual fuel that is fuel gas and liquid fuel driving generator for power generation. During the commissioning and unit start-up the exhaust spread was normal on both fuel gas and liquid fuel. After running the unit for almost a year there was a trip event. Evaluation of the trip data indicated that the exhaust temperature spread is very high when the unit was running on Liquid fuel.
It was agreed to start the unit again and perform the fuel transfer from gas fuel to liquid fuel at lower load of 5 MW, the unit tripped again when it was switched to liquid fuel due to same issue of high exhaust spread.
Further checks were performed, and it was established that the high exhaust spread is due to hardware issue, related to the fuel nozzles and liquid fuel or purge air system check valves
There are number of factors that caused the high spread exhaust issue, all of them are verified by engineering in details and recommendations are provided for the future operation of the machine without the subject issue of high exhaust spread. Most probable causes identified was the Clogging of Fuel Nozzles and issues with the Liquid Fuel check valves and Atomizing Air Purge System Check Valves.
High exhaust temperature spread is one of the major concerns in liquid fired Gas Turbines leading to low reliability of Gas Turbine & more down time. In this case study some of the rare reasons for the high spread issues & troubleshooting are analyzed and presented in detail. The information contained in this case study is broadly applied in Oil and Gas plants where Gas Turbines are installed for power generation.
A Holistic Approach to Identify the Optimum Cost-Performance Surfactants for Chemical EOR Projects
Authors: Rommerskirchen Renke , Jakobs-Sauter Britta , Ng Rick , Nijssen Patrick 
Published: October 2019

Abstract
The surfactant selection for chemical floods usually starts with an extensive lab study identifying the formulation that provides the best recovery performance. However, it is oftentimes overlooked that in a laboratory setting the requirements on product availability and applicability are less sensitive than for a field scale injection. Thus, there are various other aspects that contribute to the overall economics of chemical selection which also need to be taken into account.
Aside from the molecular properties, the manufacturing aspects have to be examined carefully to allow proper planning and ensure the supply of large volumes for full field implementation on time. Furthermore, opportunities to simplify and optimize the logistics (i.e. packaging, regulatory compliances …) help to reduce the cost of a chemical injection project. This is also strongly connected with the handling properties of the selected materials when it comes to the blending of the final injection cocktail (e.g. activity, viscosity, storage conditions, etc…).
This paper describes the crucial factors that impact the economics of a selected surfactant for a chemical EOR project, taking into account the production, transportation, delivery form, application performance, handling, amongst others. Another point that will be discussed, is the option to create in-country value and reduce logistic challenges by performing a final production step regionally close to the project site.
In the end, we conclude that involving the suppliers at a very early stage of the screening process helps to eliminate unsuitable molecules. It also allows for proper planning and leads to the most appropriate procedure. By taking into account the whole economics picture, a win-win situation can be created and the project is beneficially optimized. Forward thinking the treatment of both injected and produced fluids can be part of this optimization process.
Fracturing Fluid and Geomechanics Integration Solves Hydraulic Fracturing in the HP/HT Triassic – Jurassic Petroleum System, Krishna Godavari Basin, India
Authors: Gondalia Ravi Ramniklal , Kumar Rajeev Ranjan , Zacharia Joseph , Shetty Varun , Bandyopadhyay Atanu , Narayan Shashank , Bordeori Krishna , Singh Mukund Murari , Shah Arpit , Choudhary Dinesh , Sharma Lovely , Ray Maria Fernandes , Sarkar Samarpita , Moulali Shaik , Das Santanu , Rao Dasari Papa 
Published: October 2019

Abstract
The Triassic–Jurassic petroleum system reserves in Krishna Godavari Basin are found at 3500 to 4500 m depth with bottomhole static temperature (BHST) ranging from 270 to 340°F. Hydraulic fracturing is required to produce economically from these wells because the in-situ permeability of these sands is in the range of ~ 0.01 md. Hence, after perforations, minimal production is observed or the flash production from these wells dies out in a short time span.
Between 2010 and 2017, several appraisal wells were drilled and completed using hydraulic fracturing in the onshore Krishna Godavari Basin. However, the success rate of effective fracture placement and sustained production enhancement due to hydraulic fracturing was limited. This was attributed to insufficient understanding of rock mechanical properties and lack of a refined fluid fracturing system despite using a superior fluid system like carboxymethyl hydroxypropyl guar (CMHPG) with organometallic zirconate-based crosslinkers.
In 2018, nine wells were successfully hydraulically fractured, and sustained production from these wells was established using a simple borate-based crosslinked fluid system. A key change for the field was rather than designing and pumping fracturing fluid based on only BHST, one of the critical components that led to better proppant placement is the stable fracturing fluid that was fine tuned for the well based on factors like change of source water, tubular shear exposure time for designed fracturing treatment pumping rate, and hydrocarbon properties. This combination of rock mechanical properties and fracturing fluids used is captured as the efficiency of the fluid system, and this governed the usage of fluid loss additives, again a novel introduction for the field. Finally, the key to producing these sands was adequate cleanup and minimal guar residue to maximize the proppant pack conductivity. The paper also discusses the strategy to design fluids with minimal guar loading to reduce polymer retention and to achieve maximum fracture fluid recovery. This robust management of fracturing fluids along with understanding of rock mechanical properties can be seen in the post-fracturing production results.
Philosophy of EOR
Authors: Babadagli Tayfun 
Published: October 2019

Abstract
This paper seeks answers, through a ‘philosophical’ approach, to the questions of whether enhanced oil recovery projects are purely driven by economic restrictions (i.e. oil prices) or if there are still technical issues to be considered, making companies refrain from enhanced oil recovery (EOR) applications. Another way of approaching these questions is to ask why some EOR projects are successful and long-lasting regardless of substantial fluctuations in oil prices. To find solid answers to these two, by ‘philosophical’ reasoning, further questions were raised including: (1) has sufficient attention been given to the ‘cheapest’ EOR methods such as air and microbial injection, (2) why are we afraid of the most expensive miscible processes that yield high recoveries in the long run, or (3) why is the incubation period (research to field) of EOR projects so lengthy? After a detailed analysis using sustainable EOR example cases and identifying the myths and facts about EOR, both answers to these questions and supportive data were sought.
Premises were listed as outcomes to be considered in the decision making and development of EOR projects. Examples of said considerations include: (1) Every EOR process is case-specific and analogies are difficult to make, hence we still need serious efforts for project design and research for specific processes and technologies, (2) discontinuity in fundamental and case-specific research has been one of the essential reasons preventing the continuity of the projects rather than drops in oil prices, and (3) any EOR project can be made economical, if technical success is proven, through proper optimization methods and continuous project monitoring whilst considering the minimal profit that the company can tolerate.
Finally, through the ‘philosophical’ reasoning approach and using worldwide successful EOR cases, the following three parameters were found to be the most important factors in running successful EOR applications, regardless of oil prices and risky investment costs, to extend the life span of the reservoir and warrant both short and long-term profit: (1) Proper technical design and implementation of the selected EOR method through continuous monitoring and re-engineering the project (how to apply more than what to apply), (2) good reservoir characterization and geological descriptions and their effect on the mechanics of the EOR process, and (3) paying attention to experience and expertise (human factor).
It is believed that the systematic analysis and philosophical approach followed in this paper and the outcome will provide proper guidance to EOR projects for upcoming decades.
Case Study of Underground Gas Storage in a Lean Gas Condensate Reservoir with Strong Water-Drive
Authors: Tien Chihming , Lin Hsiaowei , Chen Jinfa , Wu Weijr 
Published: October 2019

Abstract
The largest gas discovery in Taiwan is the Tiehchenshan (TCS) gas field, which is a lean gas condensate reservoir with strong underlying aquifer. The gas reservoir has been produced since 1965, and in 1990, in light of considerations regarding domestic gas demand and available infrastructure, it was converted to underground gas storage (UGS) by injecting re-gasified LNG.
It was recently found that one of the blocks serving for gas storage is facing gradual water encroachment. In addition, between 2011 and 2012 it was discovered that average reservoir pressure suddenly increased by about 170 psi. It was surmised that this could be a result of the influence of strong water-drive due to the imbalance of injection and production over a very long period.
The aims of this study are to effectively assess the extent of gas bubble in the reservoir through the integration of a geological model, reservoir simulation, and history matching process associated with a 54-year production history; and, on this basis, to re-evaluate working and cushion gas requirements for feasible operating conditions. However, owing to the poor quality of oil production data, the black oil model is utilized for reservoir simulation rather than the compositional model. Tracer tracking of reservoir simulation is also applied to identify the movement of injected gas due to the limitations imposed by the lack of the composition model.
The reservoir simulation model for describing the dynamic behavior of the UGS was successfully developed and verified, and it was also applied to evaluate the possibility of the UGS expansibility. Results of the study suggested that one of the gas storage blocks in the UGS is no longer appropriate for its function. Instead of using it for storage, it is recommended that the gas from it be produced as quickly as possible accompanied by water encroachment.
Hydrocarbon Identification and Evaluation in a Bioturbated Reservoir with New-Generation Pulsed Neutron Technology
Authors: Kantaatmadja Budi P. , Jiang Long , Ralphie Benard , Juan Saw Li , Thien Kim Nguyen 
Published: October 2019

Abstract
High-water-saturation (Sw) bioturbated zones are generally bypassed due to the perception that those are non-oil-bearing, nonproductive zones. The major challenge in bioturbated pay zones is low resistivity, which leads to high Sw calculation. The hydrocarbon could then be bypassed in the existing completion. The high Sw also contributes to an inaccurate static model and stock tank oil originally in place (STOIIP) calculation. This study is to prove that bioturbated zones can add oil flow (as part of behind-casing opportunities from the current idle wells in many fields in Malaysia) and contribute meaningfully to the STOIIP.
The objective of this paper is to use multifunction pulsed neutron service to identify and quantify the remaining oil saturation in bioturbated reservoirs. The examples shown are from a mature field located in offshore Sarawak.
Pulsed neutron logging (PNL) is a well-established technology in casedhole reservoir monitoring and evaluation. However, the challenging environment with dual-tubing completions makes quantitative interpretation very difficult. The new generation slim pulsed neutron logging tool used in this study improves both sigma (∑) and carbon/oxygen (C/O) ratio. It also provides fast neutron cross section (FNXS), a new measurement very sensitive to formation gas and dry weight total organic carbon (DWTOC). More reliable answers help the subsurface team to select the perforation intervals confidently.
The hydrocarbon zones in bioturbated reservoirs were clearly identified. The remaining oil saturation was computed from much improved C/O ratios and the independent DWTOC method. The positive production results confirmed that the measurements and interpretation are accurate and more robust.
Experience of Distributed Temperature Survey DTS Strengthen the Understanding on Heterogeneous Carbonate in Southern Iraq Oilfield
Authors: Sidek Sulaiman , Idris Khairul Nizam , Faisal Ahmad Hisyam , Mohd Zaini Khairul Nizam , Sumainah Amr 
Published: October 2019

Abstract
This paper discusses case histories, where Distributed Temperature Survey (DTS) with Fiber Optic Enabled Coiled Tubing (FOECT) was used during stimulation treatment and well testing by the Operator in Southern Iraq oilfield.
The field was discovered in 1984 with hydrocarbon accumulation in four (4) major reservoirs, first oil production was achieved from the top carbonate reservoir in 2013. The wells were drilled to penetrate a thick carbonate reservoir which ranges from 80m to 100m thickness, subsequently completed as single selective producer with cemented casing and perforated across the targeted zone. Permeability and porosity varies drastically within same carbonate reservoir thus effective treatment fluid diversion is required to ensure the largest possible surface area of the reservoir is contacted and exposed to stimulation fluid to achieve uniform stimulation and sustainable production.
Main challenge for stimulation treatment in heterogeneous carbonate reservoirs is to achieve optimum placement of the stimulation fluid without some knowledge of, and control over where the treatment fluids flow. Traditional way to record production and injection fluid profile is via running a production logs with wireline equipment, however this require additional equipment and time. This was addressed by using CT equipped with fiber-optic real-time telemetry, that offer 3D temperature profiling which significantly improved the stimulation treatment by providing downhole monitoring throughout the entire treatment and thus a new level of control of fluid placement. In addition, the FOECT allow real-time interpretation of Pressure Transient Analysis (PTA) to evaluate the well deliverability, production performance of the stimulation treatment and basic reservoir description (e.g. permeability and total skin).
This technique helped in reducing time and the number of well intervention runs, while improving fluid placement to achieve faster, more informed stimulation treatment. Lessons learned from these case histories enhanced Operator understanding of the reservoir and led to recommendations for future treatments and potential replication.
Steps and considerations in decision making, reaching the most advantageous solution for the stimulation treatment as well as the detailed engineering evaluation for the two (2) wells candidates will be addresses in this paper.
Silhouetted Reservoir Clustering and Connectivity Network Visual Analytic Techniques in Assisted History Matching
Authors: Ghamdi Amell 
Published: October 2019

Abstract
History matching field performance is a complex and time-consuming process yet it is a crucial step towards constructing reliable predictive models. This paper presents a novel approach where visual analytics plays a role in optimizing history matching process when used as an input to Assisted History matching applications (AHM). Silhouetted Clustering (graphical representation) is the technique used to interpret and validate consistency within clusters. This technique is using k-mean algorithm, which is an Unsupervised Algorithm.
The methodology used starts with identifying the optimal number of clusters of reservoir model grid cells using Silhouetted Clustering. This was done by discovering the reservoir geo-bodies and classifying them based on patterns of static rock properties. Once the optimal number of clusters is found, sensitivity are then formulated to run on all generated clusters maintaining a property multiplier value throughout the runs. That is to detect the most effective clusters on matching field historical performance. The last step is performing sensitivity runs on the most effective group of clusters using different ranges of the property multipliers until a satisfactory match is found.
The new methodology shows a significant improvement in the matching quality of the reservoir model as a result of the cohesive clusters. Those unified clusters helped to, easily, pinpoint the candidate cluster for property modifier. This greatly improved the quality of history matching the reservoir without affecting its geo-bodies nature. The main challenge is to decide on the right number of clusters that mimics the natural grouping and distribution of the reservoir properties. The optimal number of clusters is selected based on silhouette average value, clusters' density and well separation. Therefore, Silhouetted Clustering was used to validate the cohesion within the reservoir clusters in minutes.
The novelty in this approach is introducing Silhouetted Clustering, a visual analytics technique, to optimize AHM process where we can ensure graphically how well the grid cells classified within its cluster. Moreover, this technique provides the confidence while working with the clusters knowing that the natural pattern of the reservoir is honored. The integration between Artificial Intelligence and Visual Analytics has greatly contributed to improve the overall quality of simulation models in less time.