bluuebunny/crossref_metadata_2025_split huggingface dataset:
Downhole Permanent Magnet Synchronous Motor PMSM Drive PCP - Wide Range of Speed, Output and High Efficiency
Authors: Zhongxian Hao , Guobin Zhang , Shijia Zhu , Lixin Zhang 
Published: October 2017

Abstract
Rod-tubing wear and suck rod failure are two serious problems in many oil fields, which take 45% of the whole workover. Because of the problem, in some area, the average mean-time-between-failure is only 200 days. The workover costs lots of money, not including the loss of oil production. A rodless artificial lift system, electric submersible progressive cavity pump (ESPCP), was developed and had been successfully deployed. This paper focuses on the ESPCP technology and field application.
The system included a progressive cavity pump driven by a downhole permanent magnet synchronous motor, which allowed adjusting the rotation speed between 50-500 rpm. a motor protector and a flexible shaft connecting the pump and the motor protector. More than 20 ESPCP systems has been deployed. The power of these motors was 9-15 kilowatts. The average pump setting depth was 1100 meters and the average production rate was 7-70 cubic meters per day. The application results showed that the average pump efficiency was 75.2% and the system could save more than 20% of the electricity power. In some area, the average time between workovers from 192 days of the traditional sucker rod pump to more than 400 days.
The longest running life was more than 500 days. By using this technology, the production and workover cost could be greatly saved and increased production days can be increased accordingly. Moreover, the system was located at the bottom of oil well, so less site occupation, more safety and less noise pollution to the environment were achieved.
The ESPCP system is of great of significance for some special wells such as directional well, highly-deviated well, it also can avoid the pollution in wetland and floodplain field.
A Downhole Constant Flow Nozzle Research in Waterflooding Wells
Authors: Hongwei Zhang , Jinzhong Wang , Jiaqing Yu , Fuchao Sun , Jiuzheng Yu 
Published: October 2017

Abstract
Waterflooding has been proved one of the most effective IOR method for mature field. Commingle waterflooding may result in quick breakthrough. Zonal water injection is used to decrease water-cut rise. Our aim is to make zonal flowrate constant. However, zonal flowrate usually change duo to reservoir feature and inter-layer influence. Also wellhead pressure change frequently which lead to flowrate change a lot. This paper introduces a new downhole constant flow nozzle which can keep zonal flowrate constant under the condition of pressure change. And the flowrate can be adjustable on line by instrument and then the nozzle can also keep current flowrate constant at that opening position. In this paper, a downhole constant flow nozzle in waterflooding wells is introduced. A constant nozzle is placed in each layer permanently. The nozzle has two chokes. One is used to adjust flowrate on line by instrument. The other choke is used for automatic flowrate control. The nozzle can keep flowrate constant by adjusting the opening of the choke automatically. The nozzle was also composed of arm, adjusting mechanism and two chokes. The effect of flowrate automatically control can be checked by instrument controlled by cable. The downhole constant flow nozzle has been implemented in the simulation well in jidong, PetroChina. It can realize two things. The first one is that the nozzle keep flowrate constant when tubing pressure change. Tests have been done at different position where the flowrate was adjusted from 10 to 50m3/d. Then pressure was changed from 1MPa to 10MPa. The lab test results show that the flowrate can be kept constant automatically within the accuracy 10%. In Jidong, if the accuracy can be controlled within 20%, it can meet the need of water allocation scheme. The chief merit of the nozzle is that it can not only be adjustable through instrument, but also can keep flowrate constant at any opening position. Even if the constant nozzle fails to work, the nozzle can still finish normal water injection. The test and adjustment efficiency can be improved by 15% by using this nozzle for waterflooding wells.
Cost Effective EOR in Heavy-Oil Containing Sands by Gas Injection: Improvement of the Efficiency of Foamy Flow and Pressurization
Authors: Soh Ye Ji , Babadagli Tayfun 
Published: October 2017

Abstract
Primary recovery of heavy-oil is remarkably low due to high viscosity and low energy by solution gas exsolution to drive the oil. Gas injection to improve foamy flow and also to dilute the oil in such reservoirs has been proposed as a secondary recovery method. However, because of the high costs of injected gases, efforts are needed to optimize the process by selection of proper gas type (or gas combinations) and suitable injection scheme. To achieve this goal, an experimental procedure was followed with rigorous analyses of the output. A 1.5 m long and 5 cm diameter sand-pack was first saturated with brine, which was replaced with dead oil. Then, gas solvents were injected to dead-oil containing core-holder until nearly reaching 500 psi followed by a two-day soaking period. Pressures all along the sand-pack were recorded with eight pressure transducers. Different combinations of various gas solvents (methane, CO2, and air) aiming to select the most competitive and economic formula were tested with a certain set of pressure depletion rates.
The physics of the foamy oil flow for different solvent mixtures and depletion conditions were analyzed using pressure profiles acquired, recorded oil/gas data with time, and gas chromatography and SARA analyses of the produced gas and oil. Three huff-n-puff cycles were applied. Compared with other light hydrocarbon solvents and carbon dioxide, air has its high advantage in terms of accessibility and lowered cost. Hence, attention was given to air that was mainly used to pressurize the system and increase oil viscosity due to oxidation process with an expectation of better foam quality when injected with other gases such as CO2 and methane. Methane (CH4) yielded the quickest response in terms of gas drive but, in the long run, CO2 was observed to be more effective technically. Air was observed to be effective if mixed with CO2 or methane from an economics point of view. To sum up the results, air Huff-n-Puff (HnP) followed by 2-cycles of CH4 HnP yielded 36.21% recovery, while air HnP followed by 2-cycles of CO2 HnP delivered 30.36% oil. When the gases are co-injected, air 50%-CO2 50% and air 50%-CH4 50% recovered 29.85% and 23.74% of total oil-in-place, respectively.
Massive Fracturing Evaluation to Different Well Patterns for Daqing Tight Oil Reservoirs
Authors: LI Ang , Zhuang Xiangqi , Wen Heng 
Published: October 2017

Abstract
Daqing oilfield has been produced for more than 50 years. Oil production from conventional oil pools is dropping significantly. But in recent years, massive fracturing technology were applied to difficult tight oil reservoir and unconventional gas development. More and more difficult reserves can be unlocked with this technology and that will revive oil production in Daqing field in near future, because the estimated recoverable tight oil & gas is more than conventional oil produced in past 50 years. To develop these tight oil reservoirs such as Zhou-6 and Shu-2, water injection and re-frackstimulation are required to provide economic production rate for running field under low oil price market environment.
Ageneric workflow combining reservoir qualities and engineering parameterswas proposed in this paper. The advantage of this new workflow can consider all aspects and interactions from historic reservoir pore pressure, saturation and stress to frack pumping schedule, fluid and proppant volume which will impact re-frack fracture network development in great detail and production behavior of re-frack well in an integrated model and simulation process. At the same time, how varying well spacing and injection schema impact the fracture complexity and stimulated reservoir volumeof massive re-frack stimulations.
This case study concludes that an integrated new workflow from reservoir characterization, geomechanics analysis, stimulation engineering to history matching with calibration of micro-seismic data and production performance data is possible and feasible to precisely simulate re-frack wells production behavior under varying well patterns and water injectivities.
Reservoir Characterisation Using Permanent Distributed Temperature Sensing in Coal Seam Gas Development: Success and Challenges in the Surat Basin
Authors: Bottomley W. , Furniss J. P. , Oguche I. , Konopczynski M. 
Published: October 2017

Abstract
This paper discusses the use of permanent Distributed Temperature Sensing (DTS) using optical fibres for flow zone allocation in Coal Seam Gas (CSG) production wells.
In a commingled well the allocation of total well production to the multiple stacked reservoir units is extremely important. Understanding which zones are most productive can influence future development decisions and operational practices. Additionally, the subsurface reservoir model can be calibrated and verified from the data, improving the accuracy of any forecast derived from the model.
At QGC, well completion design has focused on simplicity to drive efficiency in the execution of the ca. 2,500 wells drilled so far. These open hole completions have been run with a pre-perforated liner and no external packers to separate formations. This adds uncertainty to the interpretation of results from conventional wireline production logging tools (PLTs) run inside the pre-perforated liner. To perform a conventional PLT, the down hole pump for dewatering must be pulled, requiring a rig and making flow allocation data acquired by PLT very costly. DTS is seen as a viable alternative to PLTs, with the measurement fibre run permanently on the outside of the casing or tubing. It can remain in the well during pump operation and gather data throughout the life of the well. Typically, at QGC, a recording is made every 6 hours and is transmitted to a cloud based database for immediate visualisation.
Since a temporary single day DTS installation was trialled in 2014, QGC has run 11 permanent fibres across its Surat CSG development. This has yielded valuable information on production allocation and depletion trends. There have also been a number of challenges encountered. These include interpretation of dual phase flow, and identifying the correct geothermal gradient for interpretation. The advantages and disadvantages of casing conveyed versus tubing conveyed DTS installations are also discussed.
Real-Time Application of Integrated Well and Network Models through Smart Workflows for Optimizing and Sustaining Production Targets in an Area of Kuwait's Greater Burgan Oil Field
Authors: Al-Shammari B. , Rane N. M. , Desai S. F. , Al-Rabah A. A. , Pandey M. , Shankhdhar S. , Chacko R. , Jagannathan R. 
Published: October 2017

Abstract
The asset optimization system deployed in Kuwait's Greater Burgan oil field involved development of an integrated model of the processing facility, flowlines and wells. The objective of the integrated asset model is to achieve production optimization from the network considering well performance and restrictions combined with the limitation imposed by the surface piping network and the processing facilities.
The Burgan oil field's integrated digital field (KwIDF) automation system monitors well and plant instruments in real time from SCADA and DCS systems. It uses real time wellhead pressure and water water-cut measurements for virtual metering and calibration of the well and network models. To maintain the facility production target, various built-in production optimization scenarios are run daily and the results are visualized through smart dashboards in the state-of-the-art collaboration center. The results are shown as new optimized set points for choke or header changesto achieve facility production targets. The new set points can be automatically passed on to the SCADA system for implementation after quick validation by the stakeholders.
The paper provides new insights on the challenges of effectively running an integrated well and network model in an automated workflow through full loop, from measurement to implementing recommendations at wells and the production facility. Examples are presented on how the workflow has been used in quick analysis and decision making to optimize daily production and achieve sustainable targets in one of the production facilities at Greater Burgan field in Kuwait.
Formation Evaluation by Sourceless Logging While Drilling: NMR Case Study from Bohai Bay
Authors: Xu Jinxiu , Tan Lv , Cui Yunjiang , Liu Xiaogang , Liu Huan , Coman Radu , Tietjen Holger , Wei Gang 
Published: October 2017

Abstract
Environmental concerns have resulted ina ban onnuclear logging-while-drilling (LWD) methods containing radioactive sources and of oil-based mud in Bohai Bay, China, which is an environmental sensitive area. To avoid the risk of a radioactive source falling into the wellbore and to keep the cost of the logging program low, nuclear magnetic resonance (NMR) LWD was used as a sourceless standalone measurement, primarily to estimate the porosity and to detect permeable intervals in the Jinzhouoilfield.
This paper presents the potential and limitations of NMR-LWD in a challenging drilling environment. The resistivity of the drilling fluid was often below 0.02 ohm·m and the mud was often more than 30 K colder than the formation. These two conditions can lead to an underestimated porosity, if the NMR data is not properly corrected. Achieving rapid drilling progress was an additional goal. One borehole was drilled with a rate of penetrations (ROP) between 30 m/h and 50 m/h for analyzing the effect on data quality.
The processed NMR data shows that the high ROP has no detrimental impact on the accuracy of NMR porosity results, but, as expected, the vertical resolution is directly related to the ROP. By applying the temperature and resistivity corrections, the standalone NMR-LWD measurement compares well with offset porosity based on density-neutron logging and provides reliable data for the total porosity and for all other formation evaluation applications based on NMR data. In Bohai Bay the corrected NMR data have been successfully used to accurately detect in real-time permeable intervals bearing light oil in a complex high-porosity shaly-sandstone multilayer reservoir as well as gas intervals. In addition, the NMR data have been used to quantify bound water and movable fluids and to predict the reservoir effectiveness and productivity.
Real-Time Sanding Assessment for Sand-Free Fluid Sampling in Weakly Consolidated Reservoirs, A Case Study from Bohai Bay, China
Authors: Zhang Guoqiang , Tan Zhongjian , Khaksar Abbas , Gui Feng , Wang Shanshan , White Adrian , Lei Guowen 
Published: October 2017

Abstract
Wireline formation fluid sampling in weakly consolidated, heavy oil reservoirs has been unsuccessful in appraisal wells in the Bohai Bay area, offshore China. Poor sampling and prolonged testing time were unacceptable from both operational and formation characterization points of view. The challenges involved the production of solids during fluid sampling, contamination as well as poor and unreliable pressure testing.
An integrated study was conducted to build a fit-for-purpose geomechanical model for the study field using drilling data, well logs, formation and drill stem testing data and sanding observations in several offset wells. An analytical sanding evaluation methodologywas used and calibrated with the observed sand production in the study wells. The calibrated model was then used in a near-real time basis for new wells to optimize the sampling depth points and drawdown pressures to avoid sanding while sampling and also to speed up the sampling time to reduce operation time and costs. The aim was to use higher drawdowns and faster testing while also avoiding intervals where sand-free drawdown may not be possible.
Using the workflow in new wells has resulted in sand-free sampling at higher drawdownsas well as faster sampling speeds. In contrast, in wells where the rock mechanical aspects of fluid sampling and the root cause of sanding while sampling were not incorporated into the logging and formation testing operations, the sampling failed again due to sanding issues despite the moderate drawdown and slower sampling rate.
Real-time integrated geomechanical and formation evaluation analysisresulted in delivering sand-free fluid samples, saving 30% rig time, and more successful and reliable pressure and fluid sampling for accurate reservoir and fluid characterization.
A Comparative Workflow for Different Hydraulic Fracturing Techniques in the Western Desert Oil Fields of Egypt
Authors: ElHamid Ahmed Abd , Abbas Mohamed , Hamed Eslam , Ghareeb Mohamed , ElSebaee Mohamed , Sweedan Ahmed , Sabet Ahmed 
Published: October 2017

Abstract
"When everything else fails, frac it" was the sentiment expressed by most engineers who were working on hydraulic fracturing during the late 1970s. This statement indicates how important the hydraulic fracturing technique is, not only in stimulating, and thus greatly increasing, the well's production, but also as a powerful tool to manage the field development. Hydraulic fracturing has become the most applicable and reliable reservoir stimulation technique in all reservoir rock types, even more than the matrix acidizing techniques. Starting from 1940s, when the first hydraulic fracture was performed, until now, the improvement in the hydraulic fracturing technology has never stopped. Currently, the state-of-the-art technology in hydraulic fracturing is the channel fracturing technology or, in other words, open channel fracturing. This is a unique technique of pumping a treatment that helps in forming channels within the proppant pack in the fracture, which improves the fracture conductivity and well productivity.
This study consists of two main parts. The first part is dedicated to the evaluation of the channel fracturing technique by comparing it to conventional fracturing. This comparison depends on three primary evaluation methods. First, well testing data obtained for conventionally fractured wells and wells in which the new technology was implemented were evaluated. Second, the actual production data for offset wells, which were fractured either by conventional technique or by the new channel fracturing one, were analyzed. Finally, an economic comparison of the techniques and an assessment of the gain that can be obtained from the new channel fracturing technique over the conventional one were performed.
After the evaluation and comparison, a statistical analysis was conducted based on a sample consisting of more than 50 wells that were fractured using the channel fracturing technique. This statistical analysis aims to attain the channel fracturing treatment parameters that lead to the best corresponding production results.
These two main parts represents a full evaluation and optimization process that gives a complete picture of the channel fracturing technique and an assessment of the new technique. The assessment considers how to achieve best performance based on a sound statistical analysis constructed by actual day-to-day data and well performance. The assessment proves the economic and production value of the new technique over the conventional fracturing technique, which failed to give the same values.
Development and Application of Pulley-Free Directly-Connected Hydraulic Pumping Unit
Authors: Ye Qinyou , Wang Feng , Wang Yucai , Zhu Yongzhi , Xu Jianguo , Li Xingke , Yang Gao 
Published: October 2017

Abstract
Pulley-free directly-connected hydraulic pumping unit lift technology, developed based on the characteristics of Jilin Oilfield, can be applied to produce cost-effectively the difficult-to-produce reserves, and to improve the low fluid production and reduce the high energy consumption of developed oilfields.
Featuring low cost, low energy consumption and high efficiency with one unit serving several wells, this technology can meet the lift demand of different flow rate at different well depth. The hydraulic pumping system consists of three discrete units, namely main frame, hydraulic station and electric cabinet. The piston and sucker rod of the main frame are connected directly. When the system works, the pump of the hydraulic station provides power for the hydraulic cylinder of the main frame, which drives directly the reciprocating movements of the sucker rod to lift fluid via the reciprocating movements of the piston. The centerline of the main frame coincides with that of the casing, and so there is no unbalance loading. Substituting for the polish rod, the piston rod of the pumping unit connects directly with the sucker rod. The elimination of pulley, wire rope, rope hanger and packing box minimizes the wear parts of the system. Besides, when the system is in service, the main frame can be disassembled like tubing, having no impact on workover. The electric cabinet acquires signals via the displacement sensor and pressure sensor on the main frame and processes them, with such information as indicator diagram, stroke and stroke times displayed on the touch screen.
The ground equipment in this technology has light weight, which is about 15% of a beam pumping unit of the same model. With this technology, long stroke, low stroke times, big pump size lift, reduced rod-casing wear, prolonged maintenance free period and improved operation efficiency can be realized. Compared with existing pumping units, its investment in equipment is less. The cost of a twin well system can be reduced by more than 30%, and the energy conservation at the same fluid production rate is above 25%.
By December 2016, 24 wells of different depth in Jilin Oilfield had been subjected to pilot test successively. The "one driving one" hydraulic pumping units applied to two wells had operated stably for more than 700 days free of trouble, and the pumping efficiency had been improved by 35% compared with other types. The successful application of this system has verified its overall stability and its adaptability to the extremely cold environment in the northeast China. The "one driving two" hydraulic pumping units had been applied to 22 wells, and the test results show that both the process flow and the system are stable.