bluuebunny/crossref_metadata_2025_split huggingface dataset:
Triggering Cavitation in Multilateral Coiled Tubing Drilling by High Pressure Water Jet
Authors: Peng Kewen , Li Gensheng , Tian Shouceng , Huang Zhongwei , Zhang Zhenxiang , Zhu Bin , Nie Xiaokang 
Published: October 2017

Abstract
Recently high pressure water jet drilling is proposed for coalbed methane development by connecting nozzle with coiled tubing directly. However, rock breaking efficiency is still compromised because of the hydraulic energy loss when water flows through the small size coiled tubing. Cavitation is the formation of vapor in a liquid when the local pressure in the fluid is reduced to its saturated vapor pressure. The violent bubble collapse can cause severe damage to the materials caused by the high collapse pressure and temperature.
In this paper, based on bottomhole flow field analysis and nozzle survey, a convergent-divergent nozzle is optimized to trigger cavitation in water jet for multilateral drilling. A mathematical model coupling the flow field and bubble dynamics is used to predict the effective standoff distance for cavitation erosion. The classic Rayleigh-Plesset equation is solved by first order Euler finite difference at each step with a thermodynamic model. Then, laboratory experiments are conducted in a pressure vessel to validate the calculation results based on pitting analysis.
The results show that the divergent section of the nozzle is critical to generate low pressure regions inside the throat section, but not hindering bubble transportation towards the specimen outside. The optimized divergent angle is 20° and divergent length is 4 times nozzle diameter. In addition, it is demonstrated that the cavitation bubbles formed inside the nozzle can be transported to the outside flowfield against adverse pressure gradient due to its inertia. The effects of flow rate and ambient pressure on the effective standoff distance are investigated. Given certain ambient pressure, there exists a threshhold of flow rate, below which cavitation bubble can't be transported outside the nozzle. The experiment shows the maginitude of the cavitation impacts lies in the range of 800 MPa to 2700 MPa.
The present research, to our best knowledge, is the first systematic investigation on utilizing cavitation to increase erosion rate in multilateral CTD drilling. The nozzle proposed has a good compatibility with the coiled tubing. The proposed mathematical model can be used to assist engineering design and operational parameters adjustment.
Comprehensive Sanding Study from Laboratory Experiments, Modeling, Field Implementation, to Real-Time Monitoring, a Case Study for Hai Thach and Moc Tinh Fields, Offshore Vietnam
Authors: Hoang Son K. , Trinh Vinh X. , Tran Tung V. , Dang Tuan A. 
Published: October 2017

Abstract
This case study reports a comprehensive sanding study program for two offshore gas-condensate fields. The results from geomechanics laboratory testing and modeling of sand production were implemented into real-time monitoring of production wells using the Production Data Management System (PDMS). Sand detectors were also instrumented on all production wellheads and integrated into the real-time monitoring. The program will help define the envelopes of optimized production while ensuring safety of production facilities.
Comprehensive geomechanics laboratory testing was conducted on reservoir cores retrieved from exploration and production wells. In addition to unconfined compression tests and TWC tests, the testing included triaxial tests with acoustic velocities during hydrostatic confinement as well as deviatoric axial loading to determine formation rock strength and deformation behaviors. The laboratory results were then used to calibrate strength and elastic properties logs used in sand production modeling. Optimized production envelopes for each well could then be determined. Finally, the modeling results were integrated into PDMS so that downhole gauge pressure and sand detector readings could be monitored and managed real-time for all production wells.
The results revealed that many reservoirs in Hai Thach and Moc Tinh fields have relatively low strength and therefore moderate sanding potential. This study would help define the envelopes of optimized production while ensuring safety of production facilities. These envelopes included sanding prevention criteria in addition to criteria to optimize condensate production and minimize water production. Regarding sand production, downhole gauge pressure are monitored real-time and managed so that drawdowns are below sand production threshold at current reservoir pressures. The key functionality goal is real-time collaboration between onshore and offshore to establish reliable information for reservoir monitoring, improving modeling, and production losses mitigation, which significantly improves production through a proactive well management.
A New Concept of Sand Management Philosophy; Revolutionary & Cost Effective Solution
Authors: Hamza N. , Baghdadi F. , Yahia Z. , Madon B. 
Published: October 2017

Abstract
In the current oil price environment, all new developments are pursued with minimum capital investment and lowest possible operating cost to improve project economics. Projects that do not meet the economic criteria have to be shelved or deferred to a later date. This was the case for a green gas field development in Peninsular Malaysia which was shelved in 2016, resulting in an added preservation requirement for the newly-fabricated topside facilities and pipelines. The increase in project cost due to the preservation requirements, eroded the project economics which necessitates all possible cost reductions in order to make the overall project economically viable.
One possible area for cost reduction is the sand management. Sand production is expected from the shallower I-group reservoirs targeted in the gas development. This is based on well test results conducted in one of the appraisal wells which is further supported by a sand production prediction (SPP) study. Based on the available Particle Size Distribution (PSD) data from a Laser Particle Sieve Analysis (LPSA), the reservoir particle D50 is about 55µm and has more than 40% fines content. Due to the multilayer reservoir targets, cased hole development were designed for the well hence Internal Gravel pack (IGP) is selected as the downhole sand exclusion method.
Over the life of the field, fines production is anticipated due to the high fines content of the reservoir. There is also risk of IGP failure which could result in eroded tubings, flowlines and headers. This would be catasthropic for the green field due to its unmanned operation philosophy. Moreover, during the facilities detailed design, the provision for surface desander was eliminated to make way for a compact platform design.
This paper will describe the methodology used to assess the severity of sand production to the surface facilities using the well and reservoir parameters. The assessment results provide the basis for the field integrated sand management philosophy, which helps management to make an informed decision to eliminate the real time sand monitoring and control system requirements and also eliminate the need for platform deck extension for desander installation requirement.
Investigation of Failed LNG Boil Off Gas Transfer Line Expansion Bellows Using Finite Element Analysis Approach
Authors: Pratama E. Y. 
Published: October 2017

Abstract
Badak LNG operates two loading docks for loading LNG to transporting vessels. Each loading dock is served by two main piping systems. One piping system used to transfer the LNG from the storage tanks to the loading arms and another piping system to transfer the boil off gas (BOG) from the vessels back to the plant, to be utilized as fuel. Both piping systems are equipped with expansion bellows installed to compensate piping contraction and expansion cycles, caused by temperature cycle during operation. Several gas leaking events have occurred on expansion bellows of BOG piping, resulting in dock unavailability and may result in interruption of LNG shipping schedule. Preliminary specification review suggested that the subjected bellows operational cycles were far below the designed number of cycle. This fact, along with the evidence of bulging sections found at five to seven o'clock position, indicated possible overstress phenomenon. This study verifies the overstress phenomenon and recommends the counter measures to prevent similar problem by implementing three approaches i.e.: reviewing the bellows design and specification, developing piping stress model to obtain general overview of stress experienced by piping system in comparison to the result against the construction code, and developing finite element model to obtain more detailed stress profile within the bellows convolutions. The study results showed that the main cause of the overstress condition is a steep temperature gradient between the bottom and the top side of the bellows during transient period of cooling process of BOG piping, which happened in every loading schedule. To prevent similar failure, a change in bellows specification, modification of piping supports and installation of temperature transmitter to enable monitoring and control of BOG cooling process are recommended to be implemented.
Design and Application Evaluation of Vacuum Insulated Tubing for Wax Control in Bohai Oilfield
Authors: Liu Yigang , Shang Baobing , Wu Huaxiao , Bai Jianhua , Meng Xianghai , Ma Jun , Mu Mei , Jiang Zhaobiao 
Published: October 2017

Abstract
Bohai J Oilfield has typical characteristics of high wax content and wax precipitation point (WPT). Wax deposition in the tubing had been an ongoing problem after this Oilfield came on stream, which caused significant productivity losses. Various methods of wax control and removal, such as injection of wax inhibitor, wireline dewaxing, hot-water treatment and continuous tubing had been tried to guarantee the normal production of the wells. However, none of these methods was long-time effective. Considering that vacuum-insulated tubing (VIT) plays an important role in thermal insulation, 4 wells of J Oilfield are equipped with different length of VIT for wax control by increasing the flowing wellhead temperature (FWHT).
This paper presents the methodology for design of VIT as well as the application evaluation in the 4 wells. The apparent heat transfer coefficient of VIT is determined after analyzing the influence of coupling on VIT heat transfer properties. The distribution of wellbore temperature profile is calculated based on conservation of energy. Existing FWHT data is collected to verify the accuracy of the temperature profile calculation model. As a result, the length of VIT installed for each well is optimized through sensitivity analysis. After VIT is installed, the production performance of the 4 target wells is monitored.
After installing VIT, FWHT of the 4 wells obviously increased, and no wax deposition occurred any more when the production was stable. The actual FWHT agrees well with the prediction result, indicating the accuracy of numerical calculation.
The successful application of VIT for wax control for the first time in Bohai Oilfield indicates its effectiveness for Chinese offshore wells. This will also be one promising wax control method for other similar wells.
Maintaining Operation Excellence in Simultaneous Operation at Offshore and Delta Area
Authors: Marzuki I. , Junaedy H. 
Published: October 2017

Abstract
Robust co-activities management is one key to combine continuous production and development in upstream operation. In the context of Mahakam Block, green and brown field developments are continuously adding portfolio, simultaneously with routine production activities. Huge volume of simultaneous operation in Mahakam could be seen in 2013 operation, with more than 20 million manhours, 6 Jack up Rigs, 5 Swamp Barge Rigs, 36 Well Intervention barges, 22 Construction Barges were managed. This paper will describe specifity of simultaneous operation in Mahakam Block, and presenting improvement efforts to maintain operation excellence of simultaneous activities in offshore and swamp in the past 3 years.
Simultaneous operations in Mahakam are applicable in the field of production with drilling, well intervention, and construction / project. The improvement efforts went through mapping, gap analysis, workshop, and validation. Organization improvement efforts were including standard guideline to determine work criticality using quantitative approach, introduction of routine coactivity matrix and recurrent activities sheets. The guideline has successfully helping harmonization among operation sites and all stakeholders. Reinforcement of audit is another aspect contributing to overall excellence of TEPI safety and production performance in 2016.
New Considerations of Shale Gas CO2-EGR from Molecular Simulation
Authors: Xiaoqi Wang , Xu Jin , Jianming Li , Liang Sun , Xiaodan Liu , Zengqiang Zhai 
Published: October 2017

Abstract
Following North America, shale gas has been proved to be a success in China, considering the commercial exploitation of shale gas in Sichuan province in China, and a continuous increase in the past few years and a good momentum in the next few years. This mainly attributes to the horizontal drilling and multistage hydraulic fracturing technologies and huge capital investment. However, we need to face that even using these advanced technologies, a sharp decrease of the production during the development still exists in all shale gas wells, due to the tightness of the shale matrix and the pressure drop in the fracture network.
According to the successful experience of enhanced coalbed methane recovery all over the world, CO2 injection shows a promising future in EGR (enhanced gas recovery) process for shale reservoirs. In the meanwhile, CO2 can be simultaneously sealed underground to reduce pollution. Therefore, in order to guide the engineering process, it is of great importance to reveal the CO2 and CH4 absorption behaviors at microscopic scale,but the corresponding mechanism is as yet unclear. This is because the competitive adsorption process of CO2 and CH4 underground can be affected by a lot of parameters, such as pore size, temperature, pressure, CO2 concentration, etc., and laboratory experiment is usually difficult to carry out, due to limited laboratory temperature and pressure conditions, and difficulty in separating porous OM from shale, etc.
In this paper, we employ molecular simulation of CO2-CH4 competitive adsorption behavior in organic matter (OM) nano pores. Using Longmaxi shale as sample, OM pore structure was first characterized using FIB-SEM and scanning ion microscope, and pore-size distribution was studied using N2 adsorption. Then a simplified pillar-layer model was used to study CH4 adsorption behavior and competitive adsorption effect between CO2 and CH4, using grand canonical Monte Carlo (GCMC) method. Results indicate that nanopores with good connectivity widely exist in OM, offering important storage space for absorbed shale gas. The amount of adsorbed CH4 can increase with lower temperature and increased pressure, and overpressure will significantly increase the amount of CH4 adsorbed underground; CO2 shows high competitive adsorption ability; CO2/CH4 selectivity coefficient decreases dramatically with increasing temperature or pressure, or both, and it corresponds to deeper burial depth. CO2 EGR during shale gas exploration will be more efficient, if it is conducted after the pressure drops to a certain degree.
Unlocking Common Approach of Well Control Equipment for Mechanical Well Service
Authors: Suprihono Sanny 
Published: October 2017

Abstract
The challenge to maintain production in marginal field and to keep any related activities to be economically justified will require more optimization and innovation. Artificial lift fields using pump require many mechanical well service intervention: to install and to repair the downhole pump. Mechanical well service uses well service rig or pulling unit rig, mainly to pull and to run the tubing. One of main component of the rig is well control equipment system.
The complete package of the well control equipment system is about 30% of the rig service package. The equipment may consist of: complete BOP stack, hydraulic power unit with line, choke manifold, kill line and flare line, poor boy separator. The time needed to rig up, test, and rig down the well control equipment package has significant percentage. For simple job of artificial lift mechanical well service which main job is only pulling and running back the tubing, the percentage may be about 20% - 30%. Continuous and routine job of the mechanical well service will give significant cost impact to the total operation expenses.
One of the marginal on shore fields in Tunisia, with low productive oil production well, requires innovation to keep the production in economic limit. Cost reduction of the artificial lift well service operation is one of the main options. Optimization of the well control equipment was studied to reduce the field operation cost. Careful risk assessment had been done. Simple and low cost well control equipment was prepared. Additional procedure was introducedandsome documents related to risk control are prepared. Applying the approach, about 25% - 30% of cost saving is identified without sacrify the safety of the operation.
Well control equipment standard is an almost matured and well-regulated standard around the world. The main equipment standards are almost the same across regions, countries and companies. Mostly there are two categories of the standards related to well operation: drilling and well service. However, mostly the main well control equipment is the same for both drilling and well service. Off shore well control standard are more stringent than on shore operation. However, mechanical well service,which deals with existing perforation without any reservoir stimulation and very well-known production behaviors, are not specifically categorized in most of the standards. This type of on shore mechanical well service operation has much less risk than drilling or reservoir well service, so it is highly possible to use less well control equipment package with the proper risk assessment according to the field/well condition. The well control equipment applied in the Tunisia field will hopefully give more standard guidance for low risk marginal oil field.
Application of Allocation Algorithm for Surveillance and Optimization of Intelligent Wells
Authors: Chuen C. Mabel , Nukman M. Agus , Mandal Dipak , Salim A. S. , Sepulveda W. , Vaca J. C. , Goh K. 
Published: October 2017

Abstract
Overproduction of water is an inevitable risk in most mature oil fields. Operators have a high expenditure in both OPEX and CAPEX to delay the influx of water production, which is reducing both field life and economic value. With the advent of reservoir control technologies, oil production wells are now fitted with downhole pressure and temperature gauges and downhole flow control valves (FCV). These ‘intelligent’ wells provide valuable data for reservoir surveillance, and operators can control drawdown pressure to reduce water influx from high water production reservoirs. However, further analysis is required to identify zonal productivity index (PI) and water cut (WC) of each reservoir layer, before engineers can decide and manipulate the FCV flow area configuration of each reservoir flowing in a commingled setting. The current process of allocation using production logging is less efficient while layer-by- layer testing will cause deferments to a well's production. In offshore fields, the delay to production in order to make way for data acquisition is undesirable due to logistical difficulties. This project aims to build an optimizer to allocate reservoir parameters; PI and WC in commingled intelligent wells; and determine the most optimal setting for the FCV flow areas which will maximize oil production. This is built using data from downhole gauges, well modelling software and a multi software platform simulator (MSPS). The inbuilt algorithm in MSPS will allocate PI and WC to match simulated data calculated by a well model, to actual data from the field instruments with the lowest error possible. Once the PI and WC of each layer are known, FCV flow area settings can be configured to yield the optimal oil production. From the pilot on one well, the optimizer successfully helped engineers to increase oil production from 300 to 430 bopd in two months, while mantaining a steady yet maintainable WC increase of 11%, without any intervention costs or deferment. The allocated reservoir PI and WC allow engineers to strategize reservoir management plans specific to each producing reservoir layers, thus, improving the mechanism for reservoir surveillance.
Application of Thin-Bed Analysis in Reservoir Modelling to Unlock Further Development Potential of Thinly-Bedded Marginal Reservoirs
Authors: Chong E. E. , Azam M. N. , James P. B. , Rae S. F. , Flew S. 
Published: October 2017

Abstract
This paper describes how petrophysical thin-bed analysis is applied to an integrated static and dynamic modelling workflow to obtain a history match based on 3 years of production, for a series of relatively thin heterolithic reservoirs.
Previous reservoir simulation work based on conventional petrophysical interpretation for property modelling, indicated insufficient connected STOIIP and permeability-thickness to match flow behaviour observed from surveillance data. Therefore, an alternative thin-bed approach was proposed to address this fundamental reservoir characterization issue.
It is well known that across highly-laminated sandstone-shale intervals, the acquired log measurements of the sandstone laminations are adversely affected by shoulder effects due to inadequate vertical resolution of most logging tools. Furthermore, the resistivity of thin sandstones is suppressed by the high conductivity of silt-clay laminations which further compounds the problem. Thisleads tothe underestimation of reservoir properties and consequently, in the underestimation of hydrocarbon volumes and permeability-thickness.
The thin-bed approach utilises available core and high-resolution resistivity-based wellbore images together with open-hole logs. These are used as inputs to generate a set of petrophysical properties, via a log resolution enhancement (LRE) method, which are more representative of the reservoirs under study. The petrophysical improvements made, relate particularly to net pay thickness, porosity, permeability and saturation estimations.
This paper also demonstrates how thin-bed properties are propagated into the static modelling workflow, to produce a series of realizations which results in improved reservoir characterization, with more accurate in-place volumes and flow characteristics.
In practice, the application of thin-bed analysis requires careful refinement to 3D grid design so that the effects of thin-bed heterogeneity are captured to facilitate history matching in simulation. By integrating this thin-bed approach, an improved history match is obtained more efficiently and without significant application of local modifiers. This improvement further infers that thin-bed log analysis is much more appropriate than ‘conventional’ log analysis for thinly-bedded heterolithic reservoirs not only in this field, but potentially to many similar reservoirs in this basin, and elsewhere.
This work ultimately led toa successful infill drilling programme and opened up potential for extended development to include secondary recovery; as opposed to ad-hoc workover potential, as described in the original Field Development Plan.