bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Philosophy of R&D Management: Combining Third-Generation R&D Management With Technology Road Mapping (TRM)
Authors: Li Xianqi , Dou Hong'en , Chen Changchun , Chang Yuwen , Qu Debin , Yan Jianwen 
Published: December 2007

Abstract
This paper presents a new philosophy of research and development (R&D). it is combined the mode of third generation R&D management (Philip A. Roussel, Kamal N.Saad and Tamara J. Erickson, 1991) with technology road maping (TRM) (Jonah M. Duckles, and Edward J. Coyle, 2002, Alain Leger, Fausto Giunchilia, Ana V.Zhdanova and Niana Maynard, 2005). Main management system of the third generation R&D management and its functions, advantages and application of TRM of petroleum technology R&D were described in the paper. At the same time, milestone's elements of technology R&D and RTM's construction are discussed. This paper also point out how to keep company business target in accordance with the technology development target through identifying and prioritizing technology investment decisions, and repositioning company technology capabilities. The visions of the future technology scenario planning and translating the TRM to a technology strategy can be put forward. The methodologies, tools and templates of TRM are also presented in the paper, prioritizing technology capability and upgrading and sharing the technology future. Therefore, a chain was established among the technologies, products and services development plans, and linking of technologies to business drivers and strategy targets in order to reduce the risk of R&D of the technology. Finally, the paper proposes formulation of the TRM, and it also emphasizes that the RTM is an excellent management tool for analyzing and prioritizing potential future technology acquisition. At present, this method has been implemented to the R&D management in PetroChina.
Enhanced Mechanical Earth Modelling and Wellbore Stability Calculations Using Advanced Sonic Measurements—A Case Study of the HP/HT Kvitebjorn Field in the Norwegian North Sea
Authors: Wendt Anke S. , Kongslien Marit , Sinha Bikash K. , Vissapragada Badarinadh , Newton Adrian , Skomedal Eiliv , Renlie Lasse , Pedersen Erik Sandtorv 
Published: December 2007

Abstract
Geomechanical interpretations of inhomogeneous anisotropic materials are enhanced by three dimensional (3D) sonic measurements that provide compressional, fast shear, slow shear, and Stoneley wave slownesses in (an)isotropic drilled formations.
We investigated the Kvitebjorn high pressure high temperature (HPHT) gas/condensate field for enhanced Mechanical Earth Modelling, and wellbore stability analyses using three-dimensional sonic measurements in overburden and reservoir formations. Kvitebjorn field is situated on the Norwegian continental shelf west of the Viking Graben
In the HPHT Kvitebjorn field, major development challenges are the determination of the drawdown rate and the maximum depletion for optimum production while maintaining rock integrity. These challenges are directly related to the effect of changes in reservoir pressure on the in-situ formation stress state. Using advanced processing of sonic data, we estimated the amount of stress anisotropy, stress orientations, and stress magnitudes at particular reservoir intervals. These stress data together with measured in-situ minimum horizontal stress values were used to calibrate horizontal stress logs perviously estimated in the MEM. Furthermore, we constrained rock elastic properties (deformation, strength) using sonic slownesses and elastic shear moduli calculated from the sonic dataset. These data were later used to estimate rock strength and the onset of wellbore deformation. The two approaches allowed us to calculate (1) isotropic rock properties from the sonic slownesses, and (2) vertical and horizontal rock properties from the calculated shear moduli.
Validity of the so-calibrated MEM was subsequently tested estimating wellbore stabilities based on the isotropic rock property data, and the vertical and horizontal rock property data sets. In each case, the model was able to accurately reproduce the events observed during drilling.
The work that we present here is intended to open a new direction for geomechanical modelling: To demonstrate a new measurement allowing practical consideration of rocks as an anisotropic material, and to better constrain the effective stress ratio.
Key Aspects of Project Design for Polymer Flooding
Authors: Wang Dongmei , Seright R. S. , Shao Zhenbo , Wang Jinmei 
Published: December 2007

Abstract
After a pilot site meets the screening qualifications for polymer flooding, the injection measures and the injection formula are key points when designing a polymer flood. This paper places special emphasis on some new design factors that were found to be important during extensive experience during polymer flooding. These factors include (1) recognizing when profile modification is needed before polymer injection and when zone isolation is of value during polymer injection, (2) establishing the optimum polymer formulations, injection rates, and individual well production allocations, and (3) time-dependent variation of the molecular weight of the polymer used in the injected slugs,
At Daqing, polymers with molecular weights from 12 to 38 million Daltons were designed and supplied to meet the requirements for different reservoir geological conditions. The optimum polymer injection volume varied around 0.7 pore volume (PV),1 depending on the water cut in the different flooding units. The average polymer concentration was designed about 1,000 mg/L, but for an individual injection station, it could be much more.2,3 The injection rate should be less than 0.2 PV/yr, depending on well spacing. Additionally, the project design should follow certain rules when allocating the injection rate and production rate for individual wells.
Aluminium Alloy Tubulars—Assessment for Ultralong Well Construction
Authors: Gelfgat Mikhail Ya. , Basovich Vladimir S. , Adelman Alex , Hansen Brikt R. 
Published: December 2007

Abstract
Remaining oil and gas resources situated in easily accessible reservoirs are continuously dwindling, forcing the drilling industry to extend the range of possible targets for production activity to deposits located at considerable depths and a long way from drilling sites. With significant increase in the price of oil, a large number of deposits whose development was previously considered non-economical became suitable for exploitation. Most of these deposits lie offshore and need a borehole of considerable length to reach them from land. Recently the industry experienced a rapid increase in TMD of ERD wells, and reached the record of 11,282m TMD at Sakhalin-1 project in Russia. Several other ultra-long ERD wells include 11,278m TMD (10,728 m displacement) at Wytch Farm M-16 in UK; 11,184 m TMD (10,585 m displacement) at CN-1 in Argentina; 9,082m TMD in Visund, North Sea and etc. Drilling of such long wells, where conventional technology is stretched to its limits, is extremely challenging. Most critical of such challenges is increase in weight of the drill string, leading to considerable growth of drag. In ultra-long wells, the drag may rapidly reach values making it impossible to continue drilling without either reducing frictional forces or reducing the gravity force component acting between the contact surfaces. Reducing the weight of the drill string provides great benefits in ERD operations.
One of the solutions for extending the limits of horizontal well drilling is the replacement of conventional steel drill pipe with light alloy drill pipe. This pipe contains a number of superior properties offering important benefits. The most important of them is decrease of drag and torque in horizontal sections, which reduce the possibility of buckling initiation. Aluminium drill pipe (ADP) has extensive productive operational experience in drilling various types of wells. One of the outstanding achievements gained with utilization of ADP was
reaching the world record depth of drilling at Kola Ultra-deep Well in 1990. The drilling of this well was performed by use of downhole motors with simultaneous drill string rotation, which predominantly consisted of ADP. The drilling of this well presented a huge amount of operational experience, which in turn was effectively used in drilling less complicated wells. In fact, ADP usage averaged about 80% of all drill pipe in operation in the Soviet Union by 1980-s.
A New Inversion Method To Interpret Flow Profiles from Distributed Temperature and Pressure Measurements in Horizontal Wells
Authors: Yoshioka K. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
The increasing deployment of distributed temperature and pressure measuring devices in intelligent well completions is providing the means to monitor the inflow profiles of wells without any well intervention. If the profiles of pressure and/or temperature are affected by the inflow profiles of the various phases being produced, it is possible to estimate these flow profiles by inverting the measured temperature and pressure profiles. This inversion process is particularly challenging for horizontal wells because the pressure drop along the well is usually small, and temperature changes, caused primarily by Joule-Thomson effects, are also small.
This paper presents an inversion method that interprets distributed temperature and pressure data to obtain flow rate profiles along horizontal wells. The inversion method, which is based on the Levenberg-Marquardt algorithm, is applied to minimize the differences between the measured profiles and the profiles calculated from a forward model of the well and reservoir flow system.
We present synthetic and field examples in this paper to illustrate how to use the inversion model to interpret the flow profile of a horizontal well. The synthetic examples show that even with single-phase oil production, the inflow profile can be estimated in many cases with the inversion method developed. The method is even more robust when water or gas is produced along discrete intervals in an oil production well because of the unique temperature signature of water or gas production. We applied the inversion method to temperature and pressure profiles measured with production logs in a North Sea horizontal oil producing well. The method successfully inverted pressure and temperature profiles and the profiles of oil and water flow rates determined compared well with the flowmeter derived profiles.
A Geomechanical Facies-Based Approach to Optimize Drilling and Completion Strategy of an Unconsolidated Sandstone Reservoir, Saudi Arabia
Authors: Raba’a Ali S. , Abass Hazim H. , Hembling Drew E. , Finkbeiner Thomas 
Published: December 2007

Abstract
Drilling horizontal wells, single and multilateral, is nowadays common practice for Saudi Aramco in most of its oil and gas reservoirs (clastics as wells as carbonates) in Saudi Arabian fields. This study highlights the application of a geomechanics study to evaluate well stability drilled into a friable eolian oil-bearing sandstone reservoir. Saudi Aramco's reservoir management was eager to find the optimum mud type and azimuthal direction to place long reach horizontal wells, so as to minimize the risk of stress-induced borehole breakouts, optimize drilling mud weights, aid in making informed decisions about adequate completion design, and ensure sustainable production under depletion mode.
The reservoir rocks in this field are characterized as a "wet" eolian depositional system with four distinct depositional facies: dune, sand sheet, paleosol and playa. Grouping the lithology into these four recognizable depositional facies significantly enhanced the understanding of facies dependent rock properties and related wellbore integrity. Hence, a critical objective of the study was to combine the knowledge of reservoir and material properties with detailed analyses of the present day in situ stress field. Upon determination of the in situ stress field in the study area, wellbore stability in the principle horizontal stress directions (Shmin and SHmax) was calculated and compared and the resulting optimum direction was recommended. The effect of mud on rock strength was evaluated and the mud type that caused less rock-strength reduction was selected.
The study concluded that under undepleted conditions horizontal wells should be drilled with oil-based mud parallel to the field-derived maximum principal horizontal stress (SHmax) azimuth in order to maximize borehole stability and minimize required mud weights during drilling and completion. The results from this detailed study will be incorporated into Saudi Aramco's reservoir management decision tree, in order to maximize wellbore integrity during drilling and completion such that least damage occurs to the reservoir during drilling and in-gauge hole conditions for successful sand control completion deployment can be maintained.
The Design, Construction, Implementation, and Integration of a New Petroleum Engineering Campus in the Middle East
Authors: Platt F. M. , Fahes M. M. 
Published: December 2007

Abstract
This paper concerns the planning, construction, implementation, and integration of new state-of-the-art teaching laboratories for Petroleum Engineering at Texas A&M University at Qatar, a new international campus in the Middle East.
The results are seven laboratories designed to teach and support seven topics covered under the university curriculum for Petroleum Engineering at Texas A&M University. The laboratories were designed and built for the new campus in Doha, Qatar, to instruct the student in team programs and cover the following topics: Geology (both general and advance reservoir characterization)Core PetrophysicsFluid and Gas PVT PropertiesDrilling SystemsProduction (to include fluid measurement in up to three phases)Well Control (to include construction and implementation of a drilling rig floor for simulation)3-D Simulation Room for Reservoir Characterization
Operating Multiphase Helicoaxial Pumps in Series to Develop a Satellite Oil Field in a Remote Desert Location
Authors: Saadawi Hisham 
Published: December 2007

Abstract
Abu Dhabi Company for Onshore Oil Operations (ADCO) has recently developed one of its satellite oil fields. The field is located in a remote desert location onshore the Emirate of Abu Dhabi, in the United Arab Emirates (UAE). The development concept is based on multiphase pumping and the entire field was developed using multiphase pumps.
Two helicoaxial pumps are used to pump 10,000 b/d of crude oil with associated gas and produced water to the host facilities in a nearby field some 30 km away. The pumps are installed in series. The pumps were commissioned successfully in 2006 and have been operating since then.
Huwaila field is the first and only oil field in the world where two multiphase helicoaxial pumps are operated in series. This paper describes the design, testing and operational aspects of this unique experience.
Wellbore Isolation Intervention Devices Utilizing a Metal-to-Metal Rather than an Elastomeric Sealing Methodology
Authors: Mackenzie Gordon , Garfield Garry 
Published: December 2007

Abstract
Metal-to-metal sealing technology is a medium-to-high expansion, innovative type of seal that utilizes expanding metal to achieve a fully formed pressure barrier on a tubular wall. The presented material will highlight the evolution of common oil and gas industry wellbore isolation/intervention devices that take advantage of a sealing system with an expandable metal-to-metal approach rather than a more traditional/conventional elastomeric packing element style.
The applications for the technology within our industry are wide ranging even reaching through areas such as completions, liner hangers, sand control, and flow control. Initially the development was centered around proving the technology from a predominantly live well intervention philosopy focusing on bridge plugs and straddles. The replacement of an elastomeric sealing element applies in many environments; however, the metal-to-metal seal is designed with an extraordinary seal performance envelope that cannot be achieved by conventional elastomeric seals and is perceived to be particularily desirable within the realms of hostile, high pressure, high temperature and geothermal markets. Many common failures in these type of environments leading to NPT issues will be shown to be mitigated with a technology step change in seal design.
The results of the learning curve knowledge gained from both the design and implementation phase of the project will be compiled and introduced. Case histories to highlight the effectiveness and uniqueness of the technology will be disseminated in order to show the differentaiting technology between the use of a metal sealing methodology when compared with that of an elastomeric approach.
Evaluation of the metal-to-metal sealing technology will offer a guide in order to help in the construction of a set of criteria to fully interpret the benefits and selection of a metal sealing technology over an elastomeric seal. The contributions to our industry will be shown through the features and benefits of the metal-to-metal sealing technology over an elastomeric sealing system.
Experimental Determination of Relative Permeabilities for a Rich Gas Condensate System Using Live Fluid
Authors: App J. F. , Burger J. E. 
Published: December 2007

Abstract
Measurement of gas and condensate relative permeabilities is typically performed through steady state linear core flood experiments using model fluids. This study addresses experimental measurement of relative permeabilities for a rich gas condensate reservoir using a live, single-phase reservoir fluid. Using a live, single-phase reservoir fluid eliminates the difficulties in designing a relatively simple model fluid which replicates the complicated thermodynamic and transport properties of a near critical fluid. Two-phase flow tests were performed across a range of pressures and flow rates to simulate reservoir conditions from initial production through depletion. A single-phase multi-rate experiment was also performed to assess inertial, or non-Darcy, effects. Correlations were developed to represent both the gas and condensate relative permeabilities as a function of capillary number. A nearly 20-fold increase in gas relative permeability was observed from the low to high capillary number flow regime. Compositional simulations were performed to assess the impact of the experimental results for vertical and horizontal well geometries.
Reservoir Model Uncertainty Quantification Through Computer-Assisted History Matching
Authors: Yang C. , Nghiem L. , Card C. , Bremeier M. 
Published: December 2007

Abstract
Quantification of uncertainty in production forecasting is an important aspect of reservoir simulation studies. The uncertainty in the forecasting stems from the uncertainties of various model-input parameters, such as permeability, porosity, relative permeability endpoints, etc. Traditionally, the outcome of history matching is a set of parameter values that result in a good match of the historical production data. Clearly, the history matching process will be even more valuable if the uncertainties of these model-input parameters can be quantified in the process.
In this paper, we present a systematic history matching approach to condition a reservoir model to production data and quantify the uncertainties of history matching parameters in terms of probability density functions. The new approach utilizes experimental design and multi-objective global optimization techniques. More specifically, for a given list of uncertain parameters, the history matching process is treated as a combinatorial optimization problem to find the best combination of these parameters to achieve the minimum history match error. The combinatorial optimization problem is solved by applying a hybrid metaheuristic method that combines evolutionary algorithms, Tabu search, and experimental design techniques. In the optimization process, reservoir models containing different combinations of parameter values are automatically generated to cover a wide range of possibilities based on the principles of experimental design and Tabu search. The search space of the optimization problem is gradually reduced by adopting the natural selection mechanism to discard parameter values that do not fit field data. Finally, the posterior probability density functions of the uncertain parameters are estimated by applying Bayesian theory.
The proposed methodology is demonstrated in a real field case study of a complex oil field, which has 12 production wells and 10 years of production history. Some of the wells in the reservoir are found to be difficult to match using the traditional manual history matching approach. After applying the new approach, all the well histories are successfully matched. More importantly, the posterior probability density functions of uncertain parameters are estimated in the history matching process. The results can be further used to quantify the uncertainty in the production forecasting of follow-up recovery processes.
The Virtual Well: Guidelines for the Application of Dynamic Simulation to Optimize Well Operations, Life Cycle Design, and Production
Authors: Mantecon Juan Carlos 
Published: December 2007

Abstract
The rapid uptake of transient multiphase flow simulation of wells demonstrates the recognised value to the Industry of this relatively new technique. In offshore, subsea and deepwater well locations, and in long horizontal, multi-layer, multi-lateral, big-bore and complex well completions, Industry can benefit from dynamic simulation for sound engineering design, and optimisation of costs and production.
Dynamic simulation provides the possibility of building a virtual well that can be used to analyse "what if" case scenarios and predict specific results. It is an excellent tool to understand transient well behaviour and determine the optimum process to eliminate or minimise potential transient problems. It does not replace NODAL® analysis but fills a gap where NODAL® analysis techniques cannot provide solutions. Once the dynamic well model is validated it can also be used as an implicit gauge and/or a virtual DTS during production/injection operations.
This paper details some applications, and provides guidelines for the proper use of dynamic simulation in key areas including: well clean-up, well kick-off, watercut limit, flow stability, flow assurance (hydrates), gas lift requirements, large tubing ID flow, production optimisation, and well test equipment sizing.
Well Dynamic Simulation is a useful tool that can be used during FEED and at any stage of the well life cycle to "virtually" run through a complete case scenario and predict the well multi-phase flow behaviour (including trends and profiles of liquid hold-up, pressure and temperature), providing valuable information to optimise technical, operational and HSE integrity during design and operation of production systems.