bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of Foam Properties and Its Action on Flow Improvement of Heavy Oil
Authors: Qiang Jing Jia , Li Yanfang , Yang Xue , Zhang Zhihong , Yao Jianhua , Zhu Hongjun 
Published: July 2010

Abstract
Many difficult technological problems for heavy oil to be produced and transported have occurred due to its high viscosity and serious adhesion onto the flow channel. The fact or phenomenon that the output of foamy heavy oil is higher than that of foamless one implies that the foam existing in the foamy oil has an obvious action on the flow improvement of heavy oil. The major purpose of this study is to investigate and analyze the foam properties, and to verify its action on the flow improvement of heavy oil. Based on the evaluation of foamability, stability and comprehensive performance of the foam, and combined with the analysis of the effects of pH value, mixed salt of NaCl and CaCl2, temperature and MHZ crude oil on foaming comprehensive performance, the optimal formula of foam solution has been screened by using Waring Blender and orthogonal experimental methods. The rheological properties and viscosity-temperature characteristics of various foams, MHZ heavy oil and its foamy oils were measured and analyzed by using rheometer Rheolab QC. The flow improvement mechanism of heavy oil with foam has been discussed by combining with the analysis of the foam properties and its microstructures.
The results show that obvious synergistic actions exist among different foaming agents. For 200ml of the optimal foam solution, its foaming volume is 620ml at the room temperature, the foam half-life is 494min, the foaming composite index is 229710ml·min, and it has stronger resistances to acid, alkali, temperature and oil. The foams and foamy oils show the properties of Non-Newtonian fluid at the studied temperature range and obey the power-law fluid-flow model. The law of the viscosities changed with temperature for different foamy oils is very similar. The higher the temperature and/or the content of the foam solution is, the better the flowability of the foamy oils is, and their highest viscosity reduction rate can reach 96% or above. The apparent viscosity is insensitive to the change of temperature and/or content of the foam solution at the temperature range of 20°C to 30°C. Thus the flow improvement mechanism of MHZ heavy oil with foam can be attributed to the effects of disintegration, isolation and lubrication of the foam on the oil and its flow channels. Therefore, this study provides a theoretical foundation for the development and application of new technologies on the flow improvement of heavy oil.
Step Change in Injury Rates through Integrated Operator and Service Company Safety Management
Authors: Krus Harrie , Johan Krone Friedel , Christiansen Dave , Mientjes Ron , Dawson Mark , Flores Juan , Landgrave Stephen , Alyusuf Jihaad 
Published: July 2010

Summary
The Wells department in Brunei Shell Petroleum (BSP) achieved 1 year without a recordable case injury to any of its combined staff and contractor work force. Throughout the year, there was an average of some 350 BSP Wells staff and 750 contractor staff that participated in BSP's land and offshore oilfield activities. In this article the authors' hope is to convince you to adopt similar processes in your organization to improve the safety performance of your operations. Furthermore, the processes outlined in this paper can be used immediately by any operator, group of operators, and contractors who work co-operatively together with the aim of reducing injury rates in their circle of influence.
Since the initial implementation, the BSP and the Contractor Group safety statistics have improved dramatically over the last 2-year period as can be seen in Figure 1 below.
Low Resistivity Pay Evaluation Using Triaxial Induction in Offshore South China
Authors: Cai Jun , Wu HongShen , Shusheng Guo , Guan Hui , Desport Olivier 
Published: July 2010

Abstract
Low resistivity pay is common in China and presents a difficult interpretation challenge. One possible cause is sand-shale laminations where the presence of conductive layers dominates the resistivity measured by conventional resistivity tools which mainly sense the horizontal resistivity component. Those low resistivity layers may consist of shale or fine grain sands with high bound water. They create resistivity anisotropy and if not detected, it may result in missing or underestimating the pay.
In order to characterize laminated formations, the vertical resistivity needs to be measured and this can be achieved using a 3D induction tool. This tool uses triaxial transmitters and receivers at various spacing to measure a tensor which is inverted to extract horizontal and vertical resistivity.
Those resistivities are then used in a model based interpretation to compute the resistivity of the sand lamination and thus the saturation. Being a model based interpretation, the model needs to be validated. Some effects can be accounted for such as intrinsic shale anisotropy or dispersed clay in the sand layer. Other effects such as highly resistive cemented layer may not be compensated for and need to be identified. This paper describes some of the effects through log examples from offshore China.
Adaptive Analysis of Lifting Technology for Horizontal Wellbore in Low Permeability Oil Field
Authors: Wang Hongxing , Baoming Shen , Dongyuan Ge , Tong Wang , Baozhong Zhang , Cao Yanling , Zhu Xiufeng , Hong Sun 
Published: July 2010

Abstract
For 5½″casing medium curvature of radius in the horizontal wells, sucker rod pump can not be down to the horizon part of the wells. It can not overcome the eccentric wear problems of rods and pipe. The no-rod lifting technology for horizontal parts of horizontal wells and flowing pressure distribution, and inflow performance relationship in low permeability oil field were studied in this paper. The theory of no-rod lifting technology is that the linear electric motor, horizontal pump and oil tube are connected together. Then they are put down to horizontal section. Electromotor stator is linked with oil tube. Mover reciprocates axially to drive horizontal pump movement to realize oil pumping. Based on ground test data, electric motor can return to natural state without force after traversing deflection point in horizontal well. Besides, horizontal pump efficiency was high under horizontal condition. Results of field test for three wells showed that there was no stick when the pump went down. Average pump efficiency was 95%. Average system efficiency was 20.3%.It was found that Horizontal Electric Submersible Piston Pump can be down to 5½″ casing medium curvature of radius in the horizontal wells in any position, not only to achieve lift efficiency, but also to achieve high pump efficiency. It avoided the problem of pump inspection caused by off-center wear of casing and sucker rod. This system can enhance oil production of horizontal well by controlling reasonable flowing pressure.
Geographical Information System Applications In EP Business
Authors: Cheng Yuhua , Puasa Zurinah Yen , Endot Ernyza 
Published: July 2010

Abstract
GIS (Geographical Information System) technology has been applied to each phases of Shell E&P business process. In Shell Group, GIS is standard global tool for GIM(Geo-Information Management), Mapping, Spatial Analysis, dynamic objects tracking, environmental assessment, oil spill response etc. GGAI (Global GIS Architecture Implementation) is globally adopted in Shell operating units to deliver standardized physical infrastructure and processes. Further more, 24 hours Global GIS helpdesk has been established to assist internal GIS users when they need help in using GIS data and tools. Shell has more than 1000 GIS users located in 20+ countries. With GIS users increasing, Web GIS based ArcGIS server has provided a cost-effective solution for ‘light weight’ users. This poster will briefly introduce the major applications of GIS technology and values added to Shell EP business.
Optimizing Performance in a Deepwater Environment: Gabon & Equatorial Guinea
Authors: Saicic Petar , Gordon Jeanette , McAllan Robert 
Published: July 2010

Abstract
This paper reviews an operator's deepwater drilling campaign in Gabon and Equatorial Guinea and the principles that were established to ensure success through optimized performance.
Due to the economics involved in deepwater drilling notably the availability of suitable high specification drilling units, (and the corresponding high operating costs and mobilization times) operators with short exploration campaigns are responsive to considering the use of lesser specification vessels with a different well construction philosophy as a means of both optimizing performance and safely undertaking a project.
For this particular case study, the operator implemented current proven technologies in new ways to extend the previously regarded equipment limitations of a vessel thus providing a fit for purpose and safe solution to the financial and operational roadblocks which could have hampered the project. Specifically the implementation of surface BOP's on a dynamically positioned drillship along with riserless drilling and evaluation of a shallow gas reservoir well.
The key principles employed that ensured a successful campaign were; Trust in the teams ability to do their jobThorough well planning and risk assessment processesEstablishing a high objective. i.e. "technical limit"Adapting and innovating to a given situationLogistical planningEmphasis on accurate cost trackingEstablishing strong vendor relationships.
The principles employed in this particular success case can be implemented for any project or task in a variety of industries or applications. Ultimately success was attained through thorough planning and subsequently successful execution of the plan.
The result was that this operator was able to drill 5 wells in the same amount of time as other operators had taken to drill only one well. This paper will detail how world record breaking performance in a deepwater environment was achieved.
A Quick-and-Novel Method in Evaluating the Producing Performance of Single-Layer in the Multilayered Sandstone Oilfield
Authors: Du Qinglong , Zhu Lihong , Guo Junhui , Liying Wei , Yin Shumin , Zuo Songlin , Tang Jinrong , Cao Weifu , Liu Baolin 
Published: July 2010

Abstract
In a multilayered and heterogeneous sandstone oilfield, the corresponding adjusting measures could be taken to improve the displacement efficiency only when the producing performance of every single-layer is evaluated. As to Lasaxing Oilfield, while most of the reservoirs have been watered out, a novel methodology used to evaluate the reservoir performance based on the fine geology and Darcy's law is promoted in this paper. The producing and injecting wells are taken into an integrated system in the novel method. And based on the balance of injecting and producing in the well group, the injected water of a single-layer is allocated to wells affected by injecting according to the reservoir and developing factors, and the producing rate and thus the water cut in every individual reservoir could then be determined. And the water-cut predicting model is also promoted in this paper based on numerical simulation of reservoir conceptual model. The corresponding software is also programmed. And the method is verified by the calculating of 1200 layers of 150 wells in Daqing Oilfield, where the accuracy is more then 75%. And the WOF technology is used in 35 layers of 12 wells with high water-cut, which leads to a good result.
Hydraulic Flow Unit Based Permeability Characterization and Rapid Production Prediction Workflow for an Offshore Field, South China Sea
Authors: Guo Shu Sheng , Cai Jun , Zhou Jing , Niu Yu Qiang , Feng Li Xiang , Yu Yin Hua , Khong Chee Kin 
Published: July 2010

Abstract
This paper presents a case study of hydraulic flow unit (HFU) based permeability characterization and fast production prediction for an offshore field, South China Sea. The aim is to integrate cores, petrophysics logs, formation tester and drill string well test (DST) data together to build a generally applicable workflow for rapid production prediction immediately after logging, in order to facilitate the decision making of the drill stem testing and completion. Overall productivity of a well and productivity of each zone is critical information for well evaluation. Based on a quick yet reliable answer, operators can decide whether the well should be tested by DST /completed. If the prediction is within the acceptable accuracy range, the number of zones to be tested could be reduced. Therefore well cost can be greatly saved.
The major challenges are facing in this field are: highly laminated sand/shale sequences, strong heterogeneities, complex por-permeability relationships, and different scales of different measurements. Based on the field geological settings, total four sub areas, two sub zones were delineated. Different HFUs were identified from core data for each area and zone. The porosity-permeability models were built in each HFU. The permeability output was calibrated by formation tester interpreted effective permeability to get calibration scale factor. Based on the scale factor, a workflow was then set up to predict the production for new wells, from either core data or petrophysical data, depending on the data availability. Three DST results were used to validate the results from this workflow, giving great confidence of the applicability in the study result (the prediction accuracy is within 20% range). This case study brings following values: a quick production prediction workflow has been set up for this field; and the methodology applied is not limited to this specific field but applicable to other fields with similar formation types.
Solid Expandable Tubular Combined With Swellable Elastomers Facilitate Mulitzonal Isolation and Fracturing, With Nothing Left in the Well Bore to Drill for Efficient Development of Tight Gas Reservoirs in Cost Effective Way
Authors: Anjum M. Ghufran , Shafeeq Umair , Younas M. Avais 
Published: July 2010

Abstract
Expandable technology applied as a production string, facilitates increased fracturing, and improved conductivity, enhanced hydrocarbon production. A solid expendable system can provide an integral component in new wells and re-entry wells where low permeability reservoirs need isolation and separation for selective hydraulic fracturing or re-fracturing. This system can optimize the fracturing parameters by maintaining large diameters and providing seals for selective multi zone or zonal isolation purpose. Expandable systems provide an efficient means to isolate trouble zones and preserve hole size when well-bore tapering hinders completion. Expandables used to repair the casing have extended the life of these wells without compromising the necessary hole size.
Before swellable, inflatable packers with mechanical shifted sliding sleeves were used for isolation, as well as to provide a frac and then production flow path. These systems typically require multiple trips in and out of the well bore, and tie up both rig and frac equipment, adding to higher project economics. In the past few years, an assortment of single-trip, multiple-zone isolation completion systems (modified production packers coupled with ball-actuated farce sleeves) have been developed. The application of a solid expandable system realized another step in adding value and further bolstered project economics by unlimited number of zones or sections to be fraced because no sliding sleeves or incrementally sized balls are required.
This paper explains how solid expandable system with swellable technology can be helpful to facilitate multizonal isolation, first time fracturing and re-fracturing, multi zone fracturing, and large diameter production conduits. Integration and system development of this technology will also be discussed to illustrate the effectiveness of solid expandable system in cost effective way.
Modelling a Series of Non-Aqueous Field Scale Inhibitor Squeeze Treatments in the Heidrun field
Authors: Vazquez Oscar , van Ommen Theo , Chen Ping , Selle Olav Martin , Juliussen Bjorn , Kolstø Erlend , Gustavsen Øyvind 
Published: July 2010

Abstract
When a conventional aqueous squeeze treatment is not suitable for preventing scale formation, a non-aqueous treatment may be applied. Generally, this type of treatments includes a non-aqueous phase and can be divided into different types based on the delivery system. Despite the name, most non-aqueous treatments still contain some water, due to the scale inhibitor hydrophilic nature; it only truly dissolves in water.
The main purposes of this paper are, firstly to model a series of polymer non-aqueous scale inhibitor, SI, squeeze treatments deployed in the Heidrun field in the Norwegian sector of the North Sea. Secondly, investigate alternatives to optimize the squeeze design by studying the effect of the overflush. And finally, show the workflow to build the input data model from the available field data. All the field treatments designs under study included the injection of an amphiphilic solvent phase as the scale inhibitor carrier phase and a diesel overflush.
The simulation and optimization calculations were done using a specialized near wellbore model for scale treatments. The simulation study consisted in matching the well water cut for the time of the treatment, followed by the derivation of a pseudo adsorption isotherm, which was used to describe the SI retention in the formation. Heidrun core flooding data and SI return data were used to build the input model. Finally, based on the created input models, a sensitivity study on the effect of the overflush on the squeeze lifetime was carried out.
Creating Opportunities from Challenges in a Difficult Environment: The Role of the Petrophysicist
Authors: Azuka Akam Somadina , Maher Tom , Goring Ken , JianChun Liu 
Published: July 2010

Abstract
This paper recounts the challenges faced by an integrated study team working on fields in offshore Malaysia. These challenges included flat production since last rig activity, unwanted water/gas production and modeling difficulties, which led to poor history matches.
The team petrophysicist faced specific technical challenges. The reservoir rock (as evident from cores) is very shaly, with thinly laminated hydrocarbon bearing sands in multiple stacked reservoirs. In addition, the low salinity of the formation water further reduced the contrast between pay and non-pay rocks. The reservoirs are relatively shallow with minimal consolidation, and large washouts commonly affected density/neutron logs. Consequently, fluid typing, fluid contact identification and derivation of petrophysical evaluation parameters posed significant technical challenges.
The paper presents three selected cases that inspired unusual approaches to overcome the foregoing difficulties and also rigorously challenge/support static and dynamic models.
Case One will demonstrate how adapting an innovative permeability prediction method – the Flow Quality Indicator (FQI) Concept - helped to resolve history-matching difficulty in Dynamic simulation. The FQI concept has since been tested successfully in other clastic depositional settings in Brunei and Nigeria.
In Case Two, the model integrity was improved through checking for consistency in input and model data. In particular, a comparison of the conventional wireline saturations and the core-derived saturation profile proved the value of thin-bed evaluation. Further check was to ensure that the resultant group of saturation-height tables covered the full range of rock quality before assigning to model layers.
Case Three draws from the recommendation in Case Two for thin-bed evaluation and demonstrates how reservoir value was maximized in thinly bedded sands. Consequently, hitherto production accounting problem was resolved.
In conclusion, this paper will demonstrate that a challenging environment brings out the best in the team Petrophysicist to make contributions that do result in business game change.
CO2 IOR on North Sea Chalk: Laboratory Experiments at Reservoir Conditions
Authors: Olsen Dan 
Published: July 2010

Abstract
The performance of CO2 IOR on low-permeable chalk was tested in two reservoir condition experiments modelling the Syd Arne oil field of the Danish North Sea. Conditions were Pfluid=380 bar, NOB=120 bar, and T=115 °C. A core sample with porosity=29.4 %, and kg=1.6 mD was used. Fluids were recombined live crude oil, simulated formation water, and pure supercritical CO2. The oil-CO2 system was above the minimum miscibility pressure.
Starting at an Swi of 0.147 PV, a water-flooding was conducted that resulted in the production of 0.597 PV of oil and an Sorw of 0.256 PV. This represents the end-point for the water-flooding experiment, and was the starting point for the CO2-flooding experiment. CO2-flooding produced only water until injection of 0.476 PV of CO2 where breakthrough of a miscible oil+CO2 phase occurred, followed by a sharp rise in production of oil+CO2 without detectable fingering. At breakthrough the miscible oil+CO2 phase had high contents of hydrocarbon, which gradually decreased. After injection of 1.51 PV of CO2, the cumulate oil production during CO2-flooding was 0.197 PV and the sample had reached an SorCO2 of 0.059 PV. After this no further oil production occurred. The efficient sweep of the CO2-flooding is attributed to increased viscosity of the miscible oil+CO2 phase and to transverse layering within the sample. Corrosion and compaction of the rock sample were insignificant. Permeability change was absent within the precision of the experiment.
The experiment indicates a potential for CO2 IOR to produce significant amounts of oil from low-permeable chalk, even after a water-flooding operation. It further indicates adverse effects from corrosion and compaction to be limited.
Thermal Recovery Technology Research and Application of Thin Heavy Oil Reservoir
Authors: Wang Guofeng , Jiang Deying , Zhao Haijing , Qu Yingxin , Chen Yong , Qin Fenglan , Li Yingxin , Shao Kuilong 
Published: July 2010

Abstract
According to the geological characteristics of heavy oil reservoir in the western slope area of Daqing oilfield, the thermal production numerical simulation research was done, the parameters of steam soaking and steam flooding under different effective thickness were optimized, and also the production index of reasonable thermal production exploitation project was predicted. The results showed that when the effective thickness was 3m, the reasonable steam injection rate, steam injection strength, bottom steam dryness fraction and soak time were 120t / m, 100t / d, 50%, 5d in the phase of steam huff and puff. In the phase of steam flooding, reasonable steam injection strength, bottom steam dryness fraction, production factor and flooding conversion time were respective 390t / m • km2 • d, 50%, 1.4t / t, at the end of the fourth cycle. Seam stimulation field test started in the test area at the end of 2007, in the first cycle, the average single-well injected steam 841t, produced 222 days, produced fluid 398t, oil-producing 244t, oil/gas ratio 0.29, the development effect was basically consistent with predicted results.