bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flow Pattern and Frictional-Pressure-Loss Estimation Using Neural Networks for UBD Operations
Authors: Ozbayoglu Evren M. , Ozbayoglu Murat A. 
Published: December 2007

Abstract
Underbalanced drilling is a very commonly used technique in many drilling applications. Usually, gasified fluids are preferred for achieving underbalanced conditions. Proper estimation of hydraulic requirements becomes a more important issue for trajectories with highly-inclined angles and longer sections. Flow of two-phase fluids through circular pipes has, relatively, been well understood. However, flow of two-phase fluids through annular sections is still a challenge. Many attempts have been conducted to model two-phase flow through annular geometries, but still there exists an uncertainty at this area. It has been observed that, for annular geometries, hydraulic diameter concept is not applicable for estimating flow patterns or frictional pressure losses using the models developed for circular pipes. This study approaches to estimate the flow pattern and frictional pressure losses of two-phase fluids flowing through horizontal annular geometries using Artificial Neural Networks (ANN) rather than proposing a mechanistic model. Experimental data collected from experiments conducted at Middle East Technical University, Petroleum & Natural Gas Engineering Multiphase Flow Loop, as well as from literature in order to train the ANN. Flow is characterized using superficial Reynolds numbers for both liquid and gas phase for simplicity. The results showed that ANN could estimate flow patterns with a high accuracy (error is less than ± 5%), and frictional pressure losses with an error less than ± 30%. It is also observed that proper selection of ANN is important for accurate estimations.
Automatic Coordinated Control of Pump Rates and Choke Valve for Compensating Pressure Fluctuations during Surge and Swab Operations
Authors: Nygaard Gerhard H. , Johannessen Erling , Einar Gravdal Jan , Iversen Fionn 
Published: December 2007

Abstract
In this paper we present new methods for coordinated control of pump rates and choke valve for compensating pressure fluctuations during surge and swab operations.
In hydrocarbon well drilling, automatic control of the choke valve improves the control of the bottom-hole pressure. This has made it possible to drill wells where it previously was not possible to reach total depth, due to narrow pressure margins in the reservoir. This concept is developed further in this paper, to also include automatic control of pump rates, coordinated with the choke valve control.
In configurations where the choke valve is fitted with a flow rate controllable annulus back-pressure pump, the situation calls for structured methods for automatic and coordinated control of the main mud pump, the back-pressure pump and the annulus return choke valve.
In this paper, well known methods for multivariable control are applied to the drilling process. These methods are based on identification of coupling and interaction between system input (controllable variables), e.g. pump rates and choke valve settings, and output (measured or estimated variables), e.g. pressure at given depths. It is shown how the well pressure profile can be kept within tight margins, subject to disturbances such as drillstring movement in surge and swab operations.
Automatic coordinated control is shown through numerical simulations on a detailed, space-discretized well model. Comparisons are made with the case of complete manual control and the intermediate case where only the annulus return choke line pump is automated, using a simple linear controller.
The results with automatic coordinated control of pump rates and choke valve are very promising - the performance of such a solution, measured by variance in pressure fluctuations, is improved - compared to both the case of manual control and the case of only automated choke line pump control.
Horizontal Waterflooding in Shuaiba Carbonate Reservoir of Daleel Field in Oman: From Pilots' Performance To Development Era
Authors: Zhang Liping , Zhou Liqing , Al-Mugheiry Mohammed , Xu Kuangda 
Published: December 2007

Abstract
Daleel hydrocarbon field is located in Block-5 concession area in North Oman. The field produced oil from a Shuaiba carbonate reservoir for more than ten years in depletion mode initially with vertical wells and then horizontal wells.
Due to high depletion in the field and the need of redeveloping the field, horizontal waterflooding was selected as the best mechanism to achieve this after scrutinizing several alternatives.
To confirm the selection of the horizontal waterflooding, several pilots were implemented in selected areas of the reservoir, with closely monitoring the performance and behavior of existing and new wells. Pilot results show very favorable initial results in many cases as expected or even better.
Owing to these successful results, Daleel field is starting a new era in its history with a completely redeveloped horizontal waterflooding pattern of its two major producing blocks with the expectation to get the maximum recovery. In addition to this, the learnings from the pilot tests and the waterflooding experience gained will be the valuable adding to other blocks in Daleel field and other similar fields worldwide.
Destruction and Reconstruction of Well Patterns in Anisotropic Oil Reservoirs
Authors: Liu Yuetian 
Published: December 2007

Abstract
The mechanism of the anisotropic permeability effects on the well patterns and reservoir development are investigated by coordinate transformation, fluid flow analysis, and reservoir development concepts. The Anisotropy of reservoir permeability has destruction and reconstruction effects on general well patterns. The originally designed flooding units are broken up, and new pattern units are made up of the wells that belong to different original units. The behavior possesses strong randomness, and leads to the chaotic relationship among the injection and production wells, and uncertain productivity of the oil reservoirs. It interferes significantly the oil production and recovery. To prevent the well pattern destruction, well line directions should be either parallel or perpendicular to the principal direction of the anisotropic permeability (i.e. the fracture direction). To optimize the development effects of the anisotropic oil reservoir, the latitudinal and longitudinal well spacing of the well network are calculated from the principal values of the anisotropic permeability.
Increasing Production by Maximizing Underbalance During Perforation
Authors: Jan Badrul M. , Rae Graeme , Noor M. Ishenny , Suhadi An N , Bhd Enro Analisa Sdn , Devadass Melvin 
Published: December 2007

Abstract
The invasion of pulverized rock formation grains and the resulting "low-permeability crushed zone" is the primary cause of wellbore damage in perforated completions, as established by Behrmann et. al. In order to minimize this damage during the perforating process, it is necessary to provide a dynamic underbalance in the well that will deliberately induce flow into the wellbore for tunnel cleanup. Traditional well fluids have a limited application in depleted reservoirs as the lowest achievable density is on the order of 6.6 ppg. In many depleted reservoirs this density can represent an overbalance. It is not always desirable or operationally practical to provide this underbalance with a gas cushion, and therefore in order to achieve underbalance, it is desirable to engineer a stable fluid with non-damaging chemical properties that would have a significantly lower density. This paper reports on the formulation of super light completion fluids consisting of Shell Sarapar 147 synthetic oil [Shell MDS (M)], 3M™ Glass Bubbles as a density reducing agent and an appropriate rheology control agent. Laboratory tests show that density values as low as 5.0 ppg could be achieved. Similar mixtures were prepared and used in perforation operations for Talisman's Malaysia. A total of 72 barrels of lightweight completion fluids at about 5.5 ppg was pumped downhole and the perforation job completed successfully. Production history of the well shows a marked increase in production rate compared to neighboring wells, which produce from the same reservoir, but were perforated traditionally. This technology is not necessarily limited to depleted reservoirs. In normally pressured zones where permeability is extremely low, the fluid provides an opportunity to increase the available underbalance by an order of magnitude to assist cleanup.
Nonmetallic Unbonded Flexible Pipes for Deep Water
Authors: Bryant Mike , Bhat Shankar , Chen Bin 
Published: December 2007

Abstract
A new generation of lightweight, flexible, non-metallic, un-bonded pipes has been developed for use in subsea and deepwater floating system applications. These pipes are the first of their kind offering large savings in weight and cost to operators. In addition, the elimination of metallic reinforcements removes the associated corrosion concerns in sea water and the U-value of the pipe is improved.
The Flexible Fiber Reinforced Pipe (FFRP) is constructed from extruded polymeric layers reinforced with unbonded laminated glass-fiber tape stacks. The unique design allows the construction of lightweight flexible pipes with attractive features such as capability for high internal and external pressures, in a wide range of sizes varying from 2 inch to 16 inch. It is intended to be used in deepwater.
An overview of FFRP technology is presented in this paper. Typical designs of the pipe are described. A brief overview of qualification tests is provided along with a description of initial applications. This technology has the potential to be a ‘game changer’, enabling new, lower cost field development solutions in offshore areas around the world.
Nonmetallic Unbonded Flexible Pipes for Deep Water
Authors: Bhat Shankar , Bryant Mike , Chen Bin 
Published: December 2007

Abstract
A new generation of lightweight, flexible, non-metallic, un-bonded pipes has been developed for use in subsea and deepwater floating system applications. These pipes are the first of their kind offering large savings in weight and cost to operators. In addition, the elimination of metallic reinforcements removes the associated corrosion concerns in sea water and the U-value of the pipe is improved.
The Flexible Fiber Reinforced Pipe (FFRP) is constructed from extruded polymeric layers reinforced with unbonded laminated glass-fiber tape stacks. The unique design allows the construction of lightweight flexible pipes with attractive features such as capability for high internal and external pressures, in a wide range of sizes varying from 2 inch to 16 inch. It is intended to be used in deepwater.
An overview of FFRP technology is presented in this paper. Typical designs of the pipe are described. A brief overview of qualification tests is provided along with a description of initial applications. This technology has the potential to be a ‘game changer’, enabling new, lower cost field development solutions in offshore areas around the world.
Application of Dipole Sonic To Evaluate Hydraulic Fracturing
Authors: Tellez Oscar , Castellanos Julian , Casadiego Armando , Lopez Emiliano , Sorensen Federico , Kessler Calvin , Torne Juan Pablo 
Published: December 2007

Abstract
Hydraulic fractures are used worldwide to enhance oil and gas production. In many cases, the stimulation jobs cover multiple intervals and the evaluation of the individual zones is not a straightforward process.
In Colombia (Figure 1), it was proposed to HOCOL to run the crossed dipole sonic, inside casing before and after a hydraulic fracturing job, to evaluate changes in anisotropy due to the treatment. This paper presents the complete process, including the planning and evaluation of the logging and hydraulic fracturing, and the use of this technique to evaluate hydraulic fracturing effectiveness when multiple zones are open and fractured simultaneously.
Figure 1 Columbia's Upper Magdalena Valley.
The planning process includes the use of the dipole sonic to determine rock properties and the calibration process to adjust the computation of sanding potential and fracturing pressures.
The use of acoustic anisotropy in cased hole proved to be an effective method for evaluating the effectiveness of the fracture treatment and for defining the characteristics of the resulting fractures. This is an innovative technique; a second application well is presented in this paper including the results.
New Technologies and Applications for the Vertical Seismic Profile as a Lithostructural Tool and "Look Ahead" Mode
Authors: Hernández Gerardo , Campos Humberto , Pérez Rafael , Barrios Oscar , Bautista Ricardo , Brewer Robert J. , Torne Juan 
Published: December 2007

Abstract
Vertical Seismic Profile (VSP) technology is normally used to correlate seismic time to actual drilling depths. The introduction of new technologies for wireline tools has allowed accurate acquisition data from reflectors 500 to 700 meters below the deepest VSP level to as deep as 5400 m. The tools can tolerate temperatures up to 220 deg. C. The process of acquiring such information and analyzing it will be presented in this paper.
Selected wells will be presented as case studies for the "Look Ahead" technique. In all such studies, a "Look Ahead" VSP survey had been acquired in the intermediate phase of drilling a well, and the results were compared to the surface seismic data. After the well was completed, the VSP data was then compared to a synthetic seismogram. The results showed that the VSP was accurate, in depth, for the reflectors observed in the "Look Ahead" mode. These results confirmed that the technique was a good predictor of the depth of occurrence of litho-structural reflectors when this new technology tool is used.
More recent applications also show the value of the VSP survey as a litho-structural evaluation tool. An original litho-structural model interpreted a thin shale layer throughout a producing field. After the VSP was acquired, it was evident that the real shale thickness was at least twice the thickness interpreted for the original model. Another well drilled still later further confirmed the new, thick shale model.
The use of new technologies for VSP combined with good quality procedures in acquiring and processing seismic information has proved to be helpful in optimizing costs and making decisions especially when drilling exploratory wells.
Integration of In-Situ Fluid Measurements for Pressure Gradients Calculations
Authors: Dubost F. X. , Carnegie A. J. , Mullins O. C. , Keefe M. O. , Betancourt S. , Zuo J. Y. , Eriksen K. O. 
Published: December 2007

Abstract
Reservoir fluids often show complex compositional behaviors in single columns in equilibrium due to combinations of gravity, capillary and chemical forces. Frequently non equilibrium or non stationary state conditions are also encountered, for instance due to thermal forces acting. Recognizing these behaviors downhole is a complex process that requires a greater number of data points, fluid samples and associated laboratory analysis.
Pressure gradients with wireline formation testers are traditionally used to evaluate fluid density, fluid contacts, and layer connectivity in exploration settings. This information is today supplemented by downhole fluid analysis (DFA) measurements to reveal possible reservoir fluid heterogeneities.
Although these fluid complexities have been largely recognized, conventional pressure-depth plot and pressure gradient analysis are still performed with traditional straight line regression schemes. This process may however be misleading as fluid compositional changes and compartmentalization give distortions in the pressure gradients, which lead to erroneous interpretations of fluid contacts or pressure seals. Hence the models imposed on the pressure data to calculate pressure gradients need to incorporate a rigorous mathematical approach to respect all data available, so as to follow an objective assessment of reserves and reservoir architectures.
This paper presents a method to use combined repeated pressure and in-situ fluid measurements to provide a simple model of vertical fluid distributions, looks at the different regression schemes that can be imposed on pressure data to calculate fluid gradients with their associated uncertainties and concludes on an optimal fit approach. This data integration then allows making assessments and quality control of the different measurements and conclusions about the relevant reservoir heterogeneities.
The method is illustrated with a published case study [1] from a North Sea appraisal well, where a large compositional gradient has been observed with in-situ fluid measurements. An equation of state is elaborated from a sample and its PVT experimental results, and a compositional gradient is parametized using the DFA observations at the different depths. A polynomial fit is then given to the distributed pressure measurements and the obtained fluid density variations are compared to the fluid model ones.
Development and Application of the Discrete Gradient Method for Nonsmooth, Nonconvex Production Optimization
Authors: Mason Thomas L. , Bagirov Adil , Klunder Jan , van Berkel Jean 
Published: December 2007

Abstract
Production optimization such as optimal gas lift allocation to maximize oil production can be a non-smooth and non-convex optimization problem. In this paper, we describe the derivative free Discrete Gradient Method (DGM), with local, global and multi-start search options for non-convex and non-smooth gas lift production optimization. Results of numerical experiments with published petroleum industry test problems show that the four variants of DGM are capable algorithms. Although the DGM is best suited for non-smooth and non-convex optimization problems, it can also be used to locate reasonable solutions for smooth convex gas lift optimization problems.
Implementing Real-Time Production Optimisation in Shell E&P in Europe—Changing the Way We Work and Run Our Business
Authors: Gerrard Carl , Taylor Ian C. , Goh Keat-Choon , de Boer Frank 
Published: December 2007

Abstract
In recent years advances in computing and control technology have enabled real time monitoring, surveillance and control of reservoir, well and process; Within the Exploration and Production (E&P) industry these technologies are increasingly being applied throughout all phases of oil and gas field development and production
Arguably least attention has been given to asset operations, where the rewards are actually harvested. "Smart" technologies can significantly increase value here, provided they are properly focused and implemented, and integrated into the facilities daily operations.
The successful implementation of smart applications requires new ways of working and different skill sets of the operators and support engineers. This is a particular challenge in mature assets, where the operational style has become embedded through time.
Fieldware Production Universe, "PU" is an application developed within the Royal Dutch Shell Group, ("Shell"). Real time signals from individual wells e.g. tubing head pressure, are processed by numerical "data driven" models to estimate three phase flow from individual wells. Total production from the facility is reconciled to individual wells using these estimates.
These flow estimates change the traditional process of periodically routing a well's production to a test separator; individual well flow information is available all the time and tests are performed only when necessary to validate or update PU models. A more advanced version of PU, PU-RTO also allows the use of the models for real time production optimisation.
To get from research to a fully implemented and sustainably used product is a lengthy and sometimes arduous task. Across the industry most operators can think of at least one system that has been "rolled out" but not been fully adopted and has "died" before it delivered it's full value. Reasons for failure are many, but often centre around support and delivery of true benefit to end users.
This paper discusses Shell's experience with, PU, and it's application for real time production optimisation on the Nelson platform in the UK sector of the North Sea. The paper describes PU, how the applications were implemented, some of the challenges faced during the implementation and the changes that have had to be made, resulting in a PU becoming a sustainable part of the "way we do business".
Observations and Quantitative Analyses of Waterflood Patterns in a Chalk Reservoir Using Seismic Data, Halfdan Field, Danish North Sea
Authors: Dons Thomas , Jørgensen Ole , Gommesen Lars 
Published: December 2007

Abstract
Reservoir pressure maintenance and sweep of oil with water are the main objectives of the Halfdan field water flooding. The lower mobility of water compared to oil in the Halfdan field facilitates an effective sweep of oil but means that the water injectors require larger reservoir contact area in order to replace voidage. In Halfdan this has been the focus from first development and has been obtained by controlled formation of 10,000-15,000 ft long injection fractures by injection at fracturing conditions. Modelling has indicated that conditions for propagating injection fractures along the horizontal injectors were present, but until recently a field-wide verification of the expected uniform sweep has been pending seismic identification of the resulting water flood.
After five years of production, a seismic survey was acquired covering the developed area. Analysis of the seismic data has revealed a strong signature reflecting the water flooding of the reservoir. The seismic imaging of the sweep patterns is observed directly in the 3-D data without any 4-D processing and is of an outstanding quality even compared to what is normally seen in dedicated time lapse seismic studies. The seismic observations confirm the modelled behaviour of the Halfdan field water flood.
This paper presents examples of the seismic observations made and discusses these in a rock physics context including fluid substitution and pressure effects on acoustic impedance. It is demonstrated how the seismic results together with simple analytical models add to the quantitative description of injection under fracturing conditions by facilitating measures of fracture height, connectivity and extent.
Simulations for CO2 Injection Projects With Compositional Simulator
Authors: Hurter S. , Labregere D. , Berge J. 
Published: December 2007

Abstract
The need for CO2 emissions reduction at a large scale globally implies that CO2 injection into the subsurface be undertaken in a greater variety of geological environments that has been the case previously. Often when the storage reservoirs are saline aquifers, exploration data for proposed injection sites are extremely sparse. The special behaviour of CO2-water/brine systems (mutual solubility and chemical reactivity) adds complex processes, such as dry-out, salting-out, chemical reactions to the dynamic model. Simulation in these situations is one of few means of assessing an injection site and testing various scenarios. The accurate description of physics and chemistry in numerical simulation tools is fundamental for understanding processes, as well as designing appropriate injection or mitigation strategies.
We present simulations of CO2 injection into saline aquifers with a fully compositional code that has been expanded and enhanced to include specific phenomena, such as drying-out and salting-out. The examples illustrate the importance of pre-injection studies, as the wrong injection strategy may severely impact injectivity, putting the project in jeopardy.