bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Investigation of Three-Phase Gas-Oil-Water Slug Flow Evolution in Hilly-Terrain Pipelines
Authors: Ersoy G. , Sarica C. , Al-Safran E. M. , Zhang H.-Q. 
Published: October 2011

Abstract
A hilly-terrain pipeline consists of horizontal, upward inclined and downward inclined sections. The lack of understanding of how three-phase slug flow characteristics change in hilly-terrain pipelines may lead to inaccurate modeling of the phenomenon and thus poor pipeline and downstream facility designs. Although several slug tracking models are available, their performance has not been thoroughly tested against gas-oil-water data in hilly-terrain pipelines due to the scarcity of such data.
Three-phase gas-oil-water slug flow evolution in hilly-terrain pipelines was studied experimentally. The constructed experimental facility was a 69-m long, 50.8-mm ID outdoor facility with ±5° inclination angle for a valley configuration. Three-phase slug flow developments in the hilly-terrain section were observed and analyzed with the measured pressure drop, average liquid holdup, phase distributions and slug characteristics. This study improves the current understanding of gas-oil-water flow behavior in hilly-terrain pipelines and the effect of water cut on slug flow characteristics.
This understanding will improve the existing slug tracking models or can be used to develop new models when, necessary, for the proper design and safe operation of three-phase pipeline systems. Seven three-phase slug flow patterns were identified based on oil-water mixture in the upstream horizontal section of the hilly-terrain unit. These flow patterns were analyzed and compared with slug dissipation in the downhill section of the hilly-terrain unit. When these flow patterns were compared with two-phase slug dissipation behavior, no water cut effect was observed. For moderate and high flow rates, slugs with different oil-water mixing status had differences in slug frequencies and lengths. However, the evolution of liquid slug length distributions for 20% and 80% water cuts in the upstream horizontal section and upward inclined section did not show any significant dependence on water cut.
The Use of Attenuation and Phase Shift to Estimate Permeability Distributions from Pulse Tests
Authors: Ahn Sanghui , Horne Roland N. 
Published: October 2011

Abstract
In this work, attenuation and phase shift information acquired from pressure pulse tests at multiple frequencies was used to estimate the permeability distribution of reservoirs. By preprocessing the time series pressure data at the active well and the observation well, not only are the sizes of both the time and frequency conditioning data reduced tremendously, but also there is no need to know the flow rate. However, to put this method into practice and to know its limits, an investigation was conducted under various reservoir conditions to resolve the issues of detrending (removing transient upward trends in the pressure data) and to develop the Fourier transform procedures that are necessarily involved with this approach.
In addition to estimate horizontal heterogeneous permeability from a radial multicomposite reservoir, the method utilizing multiple frequency attenuation and phase shift information was applied to a partially penetrating well in a multilayered reservoir with crossflow to reveal the heterogeneous vertical permeability distribution.
The performance of the frequency method was investigated in comparison to straightforward pressure history matching. Quasi-Newton line-search optimization with gradient information was used for both methods. In addition, we investigated the sensitivity of the permeability estimation to perturbation in both pressure data and attenuation and phase shift information.
A heuristic method for detrending was devised which helps in obtaining accurate attenuation and phase shift information. Cases with different values of storage, skin, and boundary conditions were considered. The impact of varying the number of periods and the sampling rate were checked to determine the sensitivity of Fourier transformation.
Improved Understanding of Reservoir Connectivity in an Evolving Waterflood with Surveillance Data
Authors: Parekh B. , Kabir C. S. 
Published: October 2011

Abstract
Establishing connectivity among various injectors and producers is a key to improving the understanding of a reservoir under waterflood. This understanding improves the estimates for ultimate recovery and also helps to better define the future development plan. In deepwater turbidite reservoirs, numerical flow-simulation models are used to make performance predictions, with reservoir connectivity as one of the key uncertainties.
In the initial phase of field development, interwell tracers were used to assess the connectivity. As more wells were drilled, updates were required for the simulation models. Instead of waiting for the next phase of an ongoing tracer program, both rate-transient analysis (RTA) and capacitance-resistance model (CRM) were used to understand connectivity. The input for both RTA and CRM are the rates and pressures, which are being gathered with real-time surveillance.
This paper presents a case study to compare findings from the use of interwell tracer data with the results of CRM based on dynamic data. Another study element demonstrates the use of RTA in identifying and estimating the volume of thief zone. Attempts are made to use CRM and RTA to predict connectivity based on performance prior to experiencing water breakthrough.
These case studies demonstrate the application of RTA and CRM in ongoing waterfloods. The CRM concurred with the initial tracer results and helped to understand the change in pressure distribution with time as the field was being developed. We learned that the use of CRM can be a viable alternative to an interwell tracer program to reduce uncertainty related to injector-producer connectivity. CRM also helped in understanding the efficiency of the injectors, which is important in a facility with limited water injection capacity. The ease of use of CRM and RTA makes them useful as screening tools in the process of developing a detailed flow-simulation model.
Stand Research and Analysis of Liquid-Gas Jet-Pump's Operation Characteristics for Oil and Gas Production
Authors: Drozdov A. N. , Malyavko E. A. , Alekseev Y. L. , Shashel O. V. 
Published: October 2011

Abstract
Liquid-gas ejector is a hydraulic machine, in which the energy exchange of active fluid (liquid) and passive fluid (gas) occurs through their direct mixing. Bench research have been carried out, in which the active fluid was injected in the nozzle of LGE, a pressure of active and passive fluids, and an output pressure at different geometrical parameters (such as nozzle diameter, the diameter and length of the mixing chamber) were controlled, pressure and power characteristics were constructed and analyzed. The stand consists of a submersible multistage centrifugal pump, ejector, tank and separator. Laboratory stand has unique capabilities and provides a power pressure in the nozzle of the ejector up to 20 MPa, and an intake pressure (in the suction chamber) - up to 5 MPa. This stand is fully simulates the use of an ejector in well's and field conditions.
The use of liquid-gas ejector enables applying the technologies of water-alternating gas impact on the layer, hydro-jet method of operating wells, tandem technology of the jet device and ESP in the well. Also, the use of LGE enables to utilize associated gas by injection it into the reservoir (implementing the method of enhanced oil recovery) or in the pipeline for its transportation without flaring.
The main results are the characteristics of LGE with high efficiency in various operating conditions. The region of operation parameters of the ejector, where the highest efficiency values were achieved, was established.
LGE are easy to use, they have small overall dimensions and weight, they are able to transport corrosive fluids and to reach high efficiency; and the problem of utilization of associated gas can be solved using them. They could compete with expensive compressors, multi-phase pumps and booster units.
Pattern-Based Approach to Multiphase Flow Upscaling Using Distance-Based Clustering
Authors: Suzuki Satomi 
Published: October 2011

Abstract
Methods for multiphase flow upscaling have been investigated and proposed by numerous researchers for decades. However, technologies to generate pseudo relative permeability and assign them to simulation gridblocks have not yet reached maturity in terms of both robustness and practicality. The major limitation of dynamic pseudo function methods is that they generate as many pseudo relative permeability curves as number of simulation gridblocks, which is not manageable in real field applications. To overcome this drawback, several methods for grouping pseudo relative permeability have been proposed. However, they are either 1) computationally expensive and in need of running flow simulation or streamline simulation on every simulation gridblock, or 2) devised for ensemble-level upscaling and do not intend to preserve multiphase flow behavior on a single model basis. A practical and efficient method that can facilitate multiphase flow upscaling in routine workflow of reservoir simulation is desired.
This paper proposes a new multiphase flow upscaling technique using pattern-based approach. By utilizing a fast static algorithm, a subgrid scale profile of displacement front is rapidly generated for each of simulation gridblocks based on finescale geological description. The simulation gridblocks are grouped into clusters in accordance with the similarity of the pattern of displacement front profile in subgrid scale. Computationally efficient data mining methods that use distance-based clustering techniques are applied for the grouping of numerous gridblocks. All simulation gridblocks belonging to the same cluster can share the same pseudo relative permeability because of the strong correlation between displacement front profile and pseudo function. The method is developed in the context of local boundary condition based upscaling method so that pseudo functions are independent on gridblock positions relative to wells and fluid contacts.
MPD - Drilling Optimization Technology, Risk Management Tool, or Both?
Authors: Hannegan Don M. 
Published: October 2011

Abstract
Managed Pressure Drilling (MPD) was introduced to offshore drilling decision-makers in 2003. To garner industry attention, it was taught in a "let me show you the money" style with a focus upon its ability to mitigate the types of drilling challenges that often manifest excessive drilling non-productive time (NPT), high mud costs and failure to reach the total objective with large enough hole for optimum well productivity.
Hundreds of offshore applications have now been safely and effectively practiced from all types of offshore rigs. Compared to offset wells, NPT and mud costs are reduced significantly. Otherwise technically or economically un-drillable prospects have been drilled, increasing recoverable reserves in operator's business units. There have been no reportable well control incidents where the root cause has been attributed to the technology itself or failure of its key enabling equipment. All operators’ business units who have practiced MPD, however conservatively as an early adopter, appear to have no reservation about applying it again on challenging prospects that may benefit from its hallmark – optimizing the drilling process by precise management of the wellbore pressure profile. There is no doubt that MPD has "showed the money".
However, its track record has demonstrated other strengths of significance in today's drilling environment. MPD is being recognized as a risk management technology applicable to complex prospects whose drilling hazards, if not mitigated with best available technology, increase the risk of a well control scenario developing and time for "something else to go wrong". Un-mitigated drilling hazards may also contribute to the well being over budget and behind schedule - a human factors climate which tempts short cuts and cost savings later in drilling program and plugging & abandonment (P&A) operations that are not peer-reviewed or thoroughly vetted for added risk and potential HSE consequences.
This paper will provide evidence in the form of case studies that suggest the industry consider the positive effects on drilling costs and increased recoverable reserves as welcome by-products of MPD applications but not necessarily the primary objective of its application.
Effects of Temperature Variations on Formation Tester Pretests
Authors: Betancourt Soraya S. , Dussan V E. B. , Lake Larry W. 
Published: October 2011

Abstract
To date the analysis of pressure transients associated with formation tester pretests assumes that the temperature remains constant during the measurement. Most fluids experience a decrease in temperature when undergoing an expansion, as in the case of the drawdown; therefore, it is to be expected that the temperature of the fluid within the flowline of the formation tester will change for typical pretest conditions. The object of this study is to assess the impact of these temperature transients on the pressure signal measured with single probe formation testers.
The governing equations to analyze pressure and temperature changes in the flowline have been identified. The semianalytic solution presented here couples conductive heat transfer with conservation of mass in the flowline. Sensitivity studies and practical applications are provided to illustrate the importance of thermal effects on the pressure signal recorded during the pretest. It is demonstrated theoretically that in addition to the pretest parameters (rate and volume) and tool parameters (probe size and flowline volume), the specifics of the formation tester design and environmental conditions (pressure, temperature, type of drilling fluid) are relevant to quantify the impact of temperature effects on the measurement of sandface pore pressure with a formation tester.
It has been found that the rate of thermal equilibration during the buildup could affect the behavior of the pressure signal. In particular, thermal effects may extend the duration of the flowline storage period. The two major consequences are: 1) longer time could be required for the flowline pressure to equilibrate to the sandface pore pressure; and, 2) it is possible for flowline storage effects to mask the deep formation response, e.g., spherical flow, in the late part of the buildup. The latter could introduce errors in the interpretation of the buildup pressure signal to obtain formation mobility. Other situations of practical interest, such as "false buildups" after a dry pretest, and "builddowns", i.e., a decrease in the pressure signal after an overshoot beyond the sandface pressure during the buildup, are also addressed here.
Computation of Productivity Index with Capillary Pressure Included and Its Application in Interpreting Production Data from Low-Permeability Oil Reservoirs
Authors: Li Kewen , Chen Zengwei 
Published: October 2011

Abstract
Capillary pressure might be ignored in high permeability rocks but could not be neglected in low permeability rocks. In order to study the effect of capillary pressure on production performance in low permeability oil wells or reservoirs, the formula of calculating water cut, dimensionless total and oil productivity indices were derived by considering capillary pressure. Productivity index and water cut data were computed using the new models with capillary pressure included. The results proved that the productivity index increases with water cut in high permeability rocks but decreases with the increase in water cut within a specific range in low-permeability rocks. Water flooding experiments have then been conducted in core samples with low and high permeabilities. The experimental data also demonstrated the same relationship between productivity index and water cut as the new productivity index model foreseen. Finally the productivity index data were calculated using production data from oil wells and the results were compared with the experimental data of the productivity index determined from core flooding tests. The curves of productivity index vs. water cut obtained from the production data of oil producers were consistent with those inferred from water flooding data in core samples. Note that the core plugs were sampled from the same oil wells. The new productivity index model could be used to explain the difference in production performance between high- and low-permeability oil wells.
Impact of Asphaltene Nanoscience on Understanding Oilfield Reservoirs
Authors: Mullins Oliver C. , Ballard Andrews A. , Pomerantz Andrew E. , Dong Chengli , Zuo Julian Y. , Pfeiffer Thomas , Latifzai Ahmad S. , Elshahawi Hani , Barré Loïc , Larter Steve 
Published: October 2011

Abstract
Understanding asphaltene gradients and dynamics of fluids in reservoirs had been greatly hindered by the lack of knowledge of asphaltene nanoscience. Gravitational segregation effects on oil composition, so important in reservoir fluids, are unresolvable without knowledge of (asphaltene) particle size in crude oils. Recently, the "modified Yen model" also known as the Yen-Mullins model, has been proposed describing the dominant forms of asphaltenes in crude oils: molecules, nanoaggregates and clusters. This asphaltene nanoscience approach enables development of the first predictive equation of state for asphaltene compositional gradients in reservoirs, the Flory-Huggins-Zuo (FHZ) EoS. This new asphaltene EoS is readily exploited with "downhole fluid analysis" (DFA) on wireline formation testers thereby elucidating important fluid and reservoir complexities.
Field studies confirm the applicability of this scientific formalism and DFA technology for evaluating reservoir compartmentalization and especially connectivity issues providing orders of magnitude improvement over tradional static pressure surveys. Moreover, the mechanism of tar mat formation, a long standing puzzle, is largely resolved by our new asphaltene nanoscience model as shown in field studies. In addition, oil columns possessing large disequilibrium gradients of asphaltenes are shown to be amenable to the new FHZ EoS in a straightforward manner. We also examine recent developments in asphaltene science. For example, important interfacial properties of asphaltenes have been resolved recently providing a simple framework to address surface science. At long last, the solid asphaltenes (as with hydrocarbon gases and liquids) are treated with a proper chemical construct and theoretical formalism. New asphaltene science coupled with new DFA technology will yield increasingly powerful benefits in the future.
Mechanical Modeling of Shape Memory Polyurethane Foam for Application as a Sand Management Solution
Authors: Ozan Cem , van der Zee Wouter , Brudy Martin , Vinson Justin 
Published: October 2011

Abstract
Shape memory materials are emerging as a new class of smart materials due to their ability to recover a predetermined shape following environmental changes (e.g., thermal, chemical, magnetic) even after undergoing large deformations. Recently, a thermally activated shape memory polyurethane (SMP) foam has been developed and anticipated to be used as a novel expandable sand control tool.
To understand the SMPs behavior in reservoir conditions, a finite element model to simulate the operational life of the SMP - in-situ deployment of the foam and subsequent depletion of the surrounding reservoir - was developed, and specifics are presented in this paper. A constitutive model based on the concept of phase transitions to describe the thermo-mechanical behavior of the SMP was used along with the Drucker-Prager model to simulate the behavior of the surrounding reservoir.
An operational failure condition for the SMP-reservoir system was defined in which it is considered an operational failure if the foam-wellbore contact is compromised at any point at the foam-wellbore interface during the operational life of the SMP. Using the developed model, a set of simulations for different reservoir conditions was performed. Results show that the performance of the foam is not significantly influenced by the properties of the reservoir and the SMP stays totally conformable during its operational life.
Texas Panhandle Granite Wash Formation: Horizontal Development Solutions
Authors: Rothkopf Brian , Christiansen David J , Godwin Harrison , Yoelin Alan R 
Published: October 2011

Abstract
The Granite Wash formation in the Texas Panhandle is an active horizontal drilling trend where high initial gas rates combined with rich condensate yields create a rewarding investment opportunity for operators. The Granite Wash formation has been a drilling target for over 30 years but development accelerated rapidly after November 2004 when 20-acre downspacing was approved in the Buffalo Wallow field. In the years 2004-2008, vertical infill development was actively pursued with operators using an "assembly line" methodology that concentrated on cost reduction to achieve economic success. When soft gas prices made vertical wells economically challenging, operators turned to horizontal wells to improve the trend's economics. Previous papers [Edwards (2010), Ingram (2006)] have explored optimizing completion technology in the Granite Wash so this paper's objective is to find solutions to questions about initial production, rate decline, and liquid yields by examining the reservoir and fluid properties. The paper uses techniques developed for generalized tight gas sand reservoirs and applies Granite Wash formation data to create focused solutions. The data presented show the horizontal wells’ high initial rates can be correlated to the offset vertical well performance and the initial production declines are defined by linear flow. In addition, a technique for optimizing the number of completion stages is presented and the condensate yields are explained using an Equation of State (EoS).