bluuebunny/crossref_metadata_2025_split huggingface dataset:
Resistivity Wave for Monitoring Foam Flood Propagation
Authors: Permatasari Karina Aryanti , Reekhi Gurveen Singh , Irawan Sonny , Lubis Luluan Almana 
Published: October 2017

Abstract
In order to produce more oil in reservoir, one of the promising methods is Enhanced Oil Recovery (EOR). On the average, conventional production methods will produce only 30% of the Oil Initial In place (OIIP). The remaining 70% will be covered by EOR methods. WAG (Water Alternating Gas) has already exist to recover amount of hydrocarbon. Unfortunately, gas has several disadvantages which are less viscous, less density and causes poor sweep efficiency due to the high gas mobility. Foam is used to overcome the advantages of gas by reducing gas mobility, to increase sweep efficiency by reducing the fingering effect of gas and also foam can travel both high and low permeability region along the core sample. The identification of the foam flood location is an important aspect of monitoring the progression of foam. Resistivity is chosen to monitor foam propagation because it has higher sensitivity, suitable for higher concentration, it has no limitation of gas volume fraction, no need high energy. This experiment will focus to study on resistivity measurement, foam and monitoring foam flood. Objectives of this experiment are to determine the relationship between foam injection time, distance of foam propagation, velocity of foam using resistivity wave. To measure the effect of foam and brine concentration changed against resistivity in the presence of oil. To measure foam propagation can displace brine by the changes in saturation as time progresses in various distance.
Resistivity measure at several zones to monitoring foam propagation through a core sample. Core sample will be characterized to identify dimensional of the core plug, porosity and permeability of the core plug. The liquids, such as brine, surfactant, nitrogen gas will be characterized to obtain the value of density, viscosity, salinity of brine for each materials. All those properties will influence the resistivity readings of foam propagation. All liquids will be injected into the core sample as time progresses and it will be measured by multimeter to obtain the resistivity readings. By using Archie’s equation, the brine saturation in each zone of the core sample can be calculated and plotted against injection time. From the experiment, it will be concluded that resistivity increases only in zone 1 approximately at 125 minutes from 280 ohm.m to reach the stable stage at 1100 ohm.m and foam disintegration in zone. Decreasing water saturation in zone 1 approximately at 125 minutes, zone 2 approximately at 141 minutes, zone 3 approximately at 150 minutes. Velocity of the foam propagation approximately 0,01 cm/s and the flow rate of foam propagation was 0,11 cm3/s.
Pilot In-Situ Inflow Control Device ICD Waterflood Injector Transformation- A Case Study from Platong
Authors: Pakdeesirote A.. , Ackagosol S.. , Lewis K.. , Kitvarayut N.. , Pritchett J.. , Goh K. F. 
Published: October 2017

Abstract
Horizontal well technology has been used in the Pattani Basin to target oil and gas reservoirs since the late 1990’s. As of today, the Chevron Operated B8/32 block and Platong fields have been producing from 70 horizontal wells. While about 80 % of the horizontal wells in Platong have been completed barefoot, the use of ICD’s has been increasing since 2010. Recently, in the Platong field, two ICD equipped horizontal wells were used initially for primary production of a major reservoir, following which one of the two wells was converted into a water injector to enhance total recovery from the reservoir.
The ‘Z’ reservoir located in Platong field has significant barrels (in the millions) of oil in place with an initial gas cap and a water leg. The reservoir was initially appraised and tested with a single deviated wellbore. This well confirmed the reservoir potential and identified gas and water coning, together with sand production as the major risks to optimising oil recovery. To manage potential oil and gas coning, a reservoir development plan, based around a pair of horizontal well completions, was developed. Both well completions were designed with sand control screens incorporating ICD’s to optimize inflow along each horizontal wellbore. The wells were drilled and completed in early 2012. After collecting surveillance data and modeling the primary production performance of the reservoir, a waterflood opportunity to increase total recovery was planned. The asset team implemented the in-situ conversion of one of the horizontal wells into a waterflood injector in August 2013. Response to the water injection has been confirmed in the second well of the pair and incremental oil of &gt;50 MBO has been recovered.
This case study presents an analysis of the target reservoir, the development strategy and then captures the lessons learned from the performance of horizontal producers with ICD completions during primary production and during the later waterflood phase. The main challenges for future horizontal wells applications in Platong are relatde to thin fluvial sands and depletion. The use of ICD’s will continue to be proposed for new horizontal targets based on the positive incremental production impact.
Injection Flow Rate Control in Multiplayer Packer Well Using Bridge Eccentric Injection Mandrel
Authors: Fakhruzan Ahmad , Apriadi Ferry , Septian Meldi , Akbar M.. , Wicaksono Unggul 
Published: October 2017

Abstract
Multilayer injection will increase oil recovery greater than single-layer injection in Water Flood Project. Separated injection is able performed with a single layer system but requires a lot of injection well. Multilayer well has been proven ineffective without flow separation of each layer because permeability and reservoir pressure. Although reservoir separation can be applied by using multilayer packer, but flow rate control is base concept of injection program.
Bridge Eccentric Injection Mandrel has a configuration that provides controller of flow rate at each injection layers. There is Side Pocket Mandrel for placing nozzle when install Hydraulic Packer and adjust flowrate that in accordance with injection target. This technology provides a method to prove the packer has been set and sealed by using Double Memory Pressure Gauge placed in Side Pocket Mandrel. Inside body of Bridge Eccentric Injection Mandrel has a special groove for guide Running & Pulling Tool when perform nozzle adjustment job.
Bridge Eccentric Injection Mandrel provides high accuracy reservoir data in each layer in multilayer packer injection. This technology is proven to have a system of separation and flow rate control and installation of well completion can be performed easily. Due to proven each packer has been set and seal flow connection between the layers, it gives confidence to get a more accurate data. Flow rate test results show a little difference compared with the target of injection that is affected by the surface pressure and pressure of each layer. Replacement nozzle to regulate flow rate can be conducted using a slick line unit and rig less thereby reducing operational cost.
Implementation this flow rate control technology is able for multilayer injection in every oil field. Monitoring and surveillance for update of well data can be obtained any time with low operational cost.
Influence of Miscible CO2 Flooding on Wettability and Asphaltene Precipitation in Indiana Lime Stone
Authors: Ali Muhammad , Al-Anssari Sarmad , Shakeel Muzzamil , Arif Muhammad , Dahraj Naeem Ul. , Iglauer Stefan 
Published: October 2017

Abstract
Carbon dioxide (CO2) flooding is an EOR technique in which carbon dioxide is injected into the reservoir to improve the oil recovery. The reservoir oil and rock properties are altered when carbon dioxide interacts with the oil and rock present in the reservoir. Carbon dioxide injection alters the oil and rock properties by causing reduction in oil viscosity, oil swelling and wettability alteration of the rock. This paper will present a proposal to study the wettability alteration in carbonate formations during miscible carbon dioxide flooding. In miscible carbon dioxide flooding, the injection pressure of carbon dioxide would be kept above the minimum miscibility pressure. Thus carbon dioxide is miscible with the oil present in the reservoir.
This paper primarily focuses on understanding the effect of crude oil composition on the change in wettability and asphaltene precipitation in carbonate rocks during miscible carbon dioxide flooding. Experiments will be carried out with different crude oils (Heavy, Medium and Light) on the same carbonate rock, at reservoir conditions, in order to observe the change in rock wettability. Interaction between formation and asphaltene would be investigated by measuring precipitation quantitiy into production recovery and rock at constant CO2 reservoir pressure.
Carbonate rocks are very special due to the fact that usually carbonate rocks are oil wet and carbon dioxide tends to change the wettability of the carbonate rocks from oil wet to water wet. This change in wettability of the reservoir rock increases the oil recovery. Literature review revealed that considerable amount of research has not been done on the wettability alteration of carbonate rocks during miscible CO2 flooding process. Thus this topic needs to be further investigated and studied.
Method of Characterization of Complex Fracture Network with Combination of Microseismic using Fractal theory
Authors: Wang Wendong , Su Yuliang , Zhou Zhiwei , Sheng Guanglong , Zhou Rui , Tang Meirong , Du Xianfei , An Jie 
Published: October 2017

Abstract
Microseismic monitoring technology is widely used to characterize the fracture network and provide enough information on fracture geometry and properties. We go beyond the existing method that uses planar fractures or orthogonal conjugate fractures for representing the fracture network. Our novel method of characterization involves an integrated workflow to utilize L-system based fractal geometry to describe fracture propagation pattern, density and network connectivity. Integer programming is incorporated into matching the origination points of the microseismic events during the fracture geometry matching procession. Furthermore, multilevel of the fractal fracture network model (FFNM) is calibrated by using genetic algorithm to help specifying the properties of fracture network. The additional rate transient analysis allows to interpret the relationship between well performance and complex fracture network features. The application of this workflow on unconventional shale gas start with calculating fractal fracture network geometry and determining fracture length for both hydraulic fracture and induced fracture. And also estimating stimulated reservoir volume (SRV) and fracture parameters with combination of production data. Field case study is presented for fractured horizontal well, the matching result shows that the fracture propagation path has a good fitness with microseismic event. We also carry out rate transient analysis to interpreting the performance of complex fracture network parameters. This indicates that only connected stimulated fractures does most of the contribution to gas production. The better connectivity of multi-level fracture network, the better performance of fractured well during long time development. Besides, the most significant new finding is that SRV increases as fractal fracture induced levels increase, and this relationship appears to be fracture geometry-dependent. The novelty of this new method is expected to become a more efficient process for accurate characterization of shale reservoir complex fracture network and improvement hydraulic fracture optimization.
Change Casing Removal to a Simple and Dependable Method
Authors: Melder J. E. , Hartman C. J. , Hern G.. 
Published: October 2017

Abstract
All wells eventually come to an end, and proper Plug and Abandonment is necessary. To properly abandon a well, casing must be removed and barrier plugs set. There are many viable methods that remove casing; section milling, pilot milling, or cut and pull. While all are effective, they each have their limitations. The most common method is to cut and pull the casing. Conventional cut and pull methods require a spear to engage the casing and uses the rig to apply high loads to pull the casing. The longer the casing is, the more weight the spear and rig must handle. Removing long sections of casing also reduces the number of trips required to recover the casing from the wellbore. If cement stringers or scale buildup exists, higher pulling loads will be required resulting in shorter joints of casing being recovered on each trip due to rig/workstring limitations.
The hydraulic pulling tool eliminates rig and workstring load capacity as a limit on how much pulling force can be applied to free stuck casing. After engaging the cut casing, pump pressure is applied to activate the tool. The pressure simultaneously sets the anchor in the parent casing and initiates a pulling force in the stroking section, breaking any bond holding the casing in place. If the 24 inches of stroke length is not sufficient to completely free the casing, the tool resets with slight over pull after the pump pressure is released. The operation can be repeated until the casing is freed. Technological advances improved design providing a robust tool with a controllable applied pulling force up to 1.8 million pounds (1.2 million pounds for 9-5/8-in casing). Since the tool is activated, re-set, and deactivated by manipulating hydraulic pressure nothing needs to be dropped from surface during the casing retrieval operation.
During recent operations in wells with barite build-up an operator chose to make multiple cuts and then proceed to pull short sections of casing out of the well. Sections as short as 50 meters were pulled requiring 30 trips to cut and recover casing. After deploying the Hydraulic Pulling Tool on several similar jobs the process has changed and the casing is now pulled in as little as one cut and pull attempt. Systems are available to pull 9-5/8-in to 20-in casing.
The use of the hydraulic pulling tool eliminates the need for the rig to apply the high pull loads and instead focuses that force down hole, at the stuck point, providing a safe and efficient operation. Retrieving long sections of casing in one run, reduces the operational tasks and ultimately results in significant cost savings during plug and abandonment operations.
Comprehensive Analysis of Time Lapsed Well Productivity Index for Characterizing Well Behavior in Tight Volcanic Gas Reservoir
Authors: Vijayvargia Utkarsh , Goyal Rajat , Anand Punj Sidharth , Tiwari Shobhit 
Published: October 2017

Abstract
Raageshwari Deep Gas field is located in RJ/ON 90/1 Block in western India is a retrograde gas condensate unconventional volcanic reservoir. It consists of streaks of low permeability sand which require hydraulic fracturing to achieve commercial production. Plug and perf stage technology along with limited entry was used to ensure that most of the productive pay was stimulated. Production data, Frac and Reservoir parameter were evaluated vis-à-vis Productivity Index (PI) and interdependencies were understood.
Multiple stages in a particular well were stimulated by hydraulic fracturing with each stage having from 1 to 6 perforation clusters to ensure maximum kH coverage. Different treatment designs varying in job size, proppant type, concentration and pumping rates were prepared and executed based on the formation type, net pay and petrophysical properties. After flowback and initial cleanup, the wells were hooked to the production facility. Memory production logging was then conducted in a time phased manner and the interpreted data was used to determine the PI evolution of individual cluster of all the 93 stages in 15 wells.
Time lapse PI of individual clusters as well as specific stages were plotted against: Proppant pumped per net payAverage permeabilityEffective porosityTotal proppant pumpedElevation depths of the Fatehgarh, Basalt and Felsic formations of the reservoir stretching from north to south of the field.
Important observations resulted from this exercise such as: The top most basalt stages are attributing a large portion of the 15 wells total cumulative production. It outperformed the shallower Fatehgarh sands which were thought to be more prolific.Well PI clearly supports the changes expected in the reservoir quality from north to south of the field and is in line with the OH logs.PI of wells in a particular area shows gradual improvement in contrast to the other wells PI.Positive effects of flowing back an inferior quality pay before fracturing the upper superior quality pay.
This study will not only assist in determining the optimum proppant pumped per net pay height for different formations but also facilitate in eliminating frac stages in a well which would result in significant cost reduction in upcoming development campaign of 42 wells.
This holistic workflow will be used for refining the number of frac stages in a well as well as determining an ideal proppant quantity for a particular stage in volcanic pays. Detailed analysis of production data supported in identifying the key frac and reservoir parameters which subsequently will aid in improving hydraulic fracturing efficiency. Representative case histories of production results assisted in finalizing well services activities to improve the overall well PI.
Occurrence of Particulate Mercury in Flowback Fluids After Well Workover
Authors: Yamada Junya , Kobayashi Kenta , Shibuya Takehiro , Kawasaki Midori , Nakayama Tomofumi , Maruta Hideyuki , Kobayashi Atsushi 
Published: October 2017

Abstract
Mercury is found in raw and untreated oil and gas produced from in-situ reservoir and must be removed for stable production and response to environmental issues. For optimization of Mercury Removal Unit (MRU) in production facilities, it is important to know accurately mercury concentration and chemical form of mercury species in production fluids. In design phase of production facilities, specification of MRU may be determined based on mercury concentration in production fluids collected during Drill Stem Test (DST). However, mercury concentration and chemical form of mercury species in DST may be unstable and different from those in stable production phase, because brine and drilling fluids containing dissolved oxygen flow in wells during DST. In this paper, the sampling and mercury analysis on production fluids after acid washing in a natural gas well was conducted to investigate influences of fresh brine containing dissolved oxygen on mercury concentration and chemical form of mercury species in flowback fluids in unsteady production phase like DST and just after well workover. As the result of the sampling and analysis, particulate mercury was detected in filtered solids collected from condensate and flowback water. In addition, mercury sulfide (β-HgS: metacinnabar and γ-HgS: hypercinnabar) was identified in the filtered solids by X-ray diffractometer. These particulate mercury concentration reached a peak (condensate: 1693 µg Hg/l, flowback water: 7751 µg Hg/l) around 40 hours elapsed from the beginning of clean up flow, and then went down with the passage of time afterward. After around 2700 hours elapsed, they decreased to 72.1 µg Hg/l (condensate) and 131 µg Hg/l (flowback water). At the same time, pH and total iron concentration in flowback water at that time were close to those in stable production phase. Hence, these results indicate that particulate mercury in production fluids was generated by the reaction of dissolved oxygen in workover fluids with hydrogen sulfide and elemental mercury in natural gas. Therefore, the occurrence of particulate mercury in flowback fluids after the well workover is considered to be temporary, and not to be produced in stable production phase. Although further investigations will be needed for the interpretation of mercury analysis results in the sampling and analysis, these results will be an important knowledge for interpretation of mercury analysis at DST.
Successfully Unlocking New Deep Reserves and Overcoming High-Temperature Environment Using Novel Advanced Hostile Wireline Formation Tester in North Malay Basin, Malaysia-Thailand Joint Development Area
Authors: Costam Y. R. , Fadjarijanto A.. , Zakaria Z. U. , Setiawan A. S. , Pushiri M. F. , Carigali C. Jiraratchwaro , Lee C. Y. , Iyer M. S. , Zuilekom T. V. , Parashar S.. , Bagir M.. , W. Z .M Ivan 
Published: October 2017

Abstract
Gas fields in a Malaysia-Thailand joint development area (MTJDA) are well-known to have the presence of high CO2 concentration and high-temperature reservoir characteristics. Sophisticated tools are necessary to measures important data to support further development and reservoir management of this field. Thus, reservoir data, such as pressure and fluid type, become crucial in terms of achieving production targets. Fields operated by this operator are located in the North Malay Basin, a few hundred kilometers from the onshore border of Malaysia and Thailand.
High bottom hole temperatures (BHTs) limits data gathering runs and challenges associated with fresh water made it more crucial to identify and qualify fluid types for further field development. The extensive wireline formation pressure testing and sampling (WFPT&S) program is mandatory to evaluate the viability of field development. Additional challenges included low porosity-low mobility reservoirs where fluid collection at low contamination in reservoirs with elevated temperatures of approximately 410°F (210°C) is considered a necessity. This operator pioneers the use of novel hostile wireline formation testers globally. Reliable pressure and downhole fluid analysis data should lead to production optimization.
The ability of fluid characterization using a pump-out formation tester coupled with downhole fluid identification has been introduced to help improve decision making and provide real-time data and the capability to pump out high-temperature formation fluid and acquire samples that meet expected contamination levels. As a result, fluid contact, formation pressure, fluid type, reservoir mobility, and CO2 content, which are the primary drivers of production optimization and field development are able to be determined successfully. In addition, new deep reserves could potentially be discovered in the MTJDA concession that are economically accessible with extreme high-temperature tools.
This paper discusses the use of a novel hostile wireline formation tester to collect low contamination samples at a predetermined level in hostile reservoir conditions with elevated temperature of 410°F (210°C). Challenges, considerations, and results are detailed.
This novel tool has proven lower CO2 content than expected in deeper reservoirs with elevated temperature up to 410°F (210 °C). This is the deepest well ever drilled by this operator in a development drilling campaign.
Accelerated Depreciation Increase the Economical of PSC Contractors Project in Indonesia
Authors: Jaluakbar Wisnu , Putra Iswahyudi Sondi 
Published: October 2017

Abstract
The drop in oil prices during last 2 years caused many oil and gas projects in global to be delayed, and even canceled, because the project was considered uneconomical to run under the current low oil price conditions. The postponement also happen in Indonesia and seem to increase the deficit between the total oil and gas production and total oil and gas consumption in the coming period. To overcome this situation, incentives should be given by Government of Indonesia immediately to increase the projects economics. The process of granting incentives, if possible, should not reduce state revenues. Using scenario analysis, this study finds that accelerate depreciation method does not have a big influence to economics of POD/POFDs when the POD/POFDs have high investment. When the investment to POD/POFDs was not too high, the accelerate depreciation will accelerate the investment return that eventually will increase the IRR and NPV values.