bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time 3D Earth Model Updating While Drilling a Horizontal Well
Authors: Malinverno Alberto , Andrews Ballard , Bennett Nicholas , Bryant Ian , Prange Michael , Savundararaj Philip , Bornemann Ted , Raw Ian , Britton David , Peters J. Gary 
Published: December 2007

Abstract
We describe here a test of a new technology for successful drilling of horizontal wells in thin oil columns. We constructed a three-dimensional (3D) earth model of the overburden and of the target reservoir layers on the basis of predrilling data and updated this model in real time on the basis of logging-while-drilling (LWD) measurements transferred to remote locations using the World Wide Web. This strategy allowed us to check and update the planned drilling trajectory continuously with all the information available at any given time.
We used uncertainties in the depth of markers observed in a number of offset vertical wells to determine the uncertainty in the thickness of layers in the earth model. This 3D model comprised best estimates of the thicknesses and a covariance matrix that quantified their initial uncertainties. We then drilled a pilot well. Trajectory data, LWD logs, and resistivity images from downhole measurement-while-drilling (MWD) and LWD tools were transmitted in real time from the Simpson No. 22 drill site in Indiana to a prototype application running in Connecticut. As we acquired new measurements in the pilot well, we compared log curves predicted by the model to the measured logs. Our prototype allowed an interpreter to update the location of markers as the well was drilled; an update of the entire 3D earth model and its uncertainty was then automatically computed in near-real time. Quantified uncertainties are key in this stage to ensure that the model update is in agreement with all the data considered previously. This procedure was repeated while drilling the horizontal drain hole, which was successfully steered within a dipping 6-ft-thick layer for 808 ft.
Our prototype also allowed for remote collaboration: 3D model updates, LWD data, and resistivity images were available to collaborators who were connected to the network and simultaneously ran copies of the prototype at additional locations. In particular, the remote availability of real-time resistivity images was key to the successful well placement, as these images show how the well trajectory follows the layering. Remote collaboration means that drilling decisions can be made collaboratively by a globally distributed team in a secure network environment. This can be a key capability for geosteering, especially in remote locations or when staffing is constrained.
Study of Gas-Condensate Well Productivity in Santa Barbara Field, Venezuela, by Well Test Analysis
Authors: Briones Mario , Zambrano Judith A. , Zerpa César 
Published: December 2007

Abstract
Numerous gas condensate well production data have shown that well productivity is severely affected when the bottom hole flowing pressure drops below the fluid dew point pressure. This productivity reduction is caused by liquid accumulation around the well. It is essential to take account of this ‘condensate blockage’ effect when calculating well productivity since productivity losses can be significant.
Published laboratory, simulation and well-test data have shown that at bottom hole flowing pressure below the dewpoint pressure three regions are created with different liquid saturation.
Since the retrograde condensation has an important impact on gas condensate well productivity, the optimum exploitation of these reservoirs depends on the ability to diagnose condensate bank. Well test data has proven to be one of the few reliable field data of practical use to detect the existence of retrograde condensation. In Santa Barbara field, the biggest Venezuelan gas-condensate field, application of the latest practical well-test analysis methods contributed to demonstrate the presence of velocity stripping and retrograde condensation despite conventional reservoir engineering analysis did not show such phenomena.
The paper discusses how the use of two and three radial composite model helped to gain a better understanding of Santa Barbara condensate reservoir behaviour when 1999 to 2001 well tests were reinterpreted. As velocity stripping was detected, near well bore relative permeability measurements were proposed in order to take account of the phenomena which occur at high flow rates when calculating well productivity in the field-scale simulation model.
Relative Permeability from Capillary Pressure
Authors: Papatzacos Paul , Skjæveland Svein M. 
Published: December 2007

Abstract
A new theory is reviewed for single-component, two-phase flow in porous media. It includes wettability and capillary pressure as integral parts of the thermodynamic description and does not make use of the relative permeability concept. However, by providing a capillary pressure correlation, we are able to extract relative permeabilities and to show good consistency between rock property correlations.
Wettability Effect on Oil Relative Permeability During a Gravity Drainage
Authors: Pedrera B. , Bertin H. , Hamon G. , Augustin A. 
Published: December 2007

Abstract
Gravity assisted gas displacement of oil in reservoirs is increasingly being considered. Accurate estimates of relative permeabilities are needed to understand and predict fluids motion, especially when very low oil saturations are reached.
The present work aims at conducting gravity drainage experiments in laboratory conditions. It particularly outlines wettability effect on recovery and relative permeabilities. The study is divided in two parts. In the first one, gravity drainage experiments under secondary conditions are performed with different core wettabilities. In the second one, relative permeabilities are determined from the experimental data using a semi-analytical calculation and an identification method based on a numerical model.
The experiments are performed on long (one meter) artificial consolidated porous media. Average porosity is 40% and absolute permeability to brine is around 6 Darcy. Fluids are air, refined oil of moderate viscosity and a brine. Wettability is modified by an ageing technique using a crude oil in place of the refined oil and keeping the core in an oven at controlled temperature and time. This process provides reproducible conditions of wettability estimated using the Amott test. During gravity drainage, oil recovery is recorded (weighting machine) and saturation profiles are measured using a gamma ray attenuation technique.
The oil relative permeabilities are determined through an analytical treatment of the multiphase displacement model, where capillary pressure is known. They are directly calculated from the different saturation profiles measured along the core and then expressed in a Corey's form. In addition, experimental observations are matched as closely as possible by numerical simulations.
The results are presented in terms of oil recovery and relative permeability. Oil recovery depends on wettability: a larger production time is observed for oil-wet media compared to the water-wet core and final oil recovery increases when the core is being oil-wet. The wettability effect on relative permeability is less obvious: it is strong between the water-wet case and the other situations, but weaker when considering the intermediate media.
Laboratory Measurements of Condensate Blocking and Treatment for Both Low and High Permeability Rocks
Authors: Al-Anazi Hamoud A. , Pope Gary A. , Sharma Mukul M. , Metcalfe Robert S. 
Published: December 2007

AbstractCoreflood experiments were conducted in Berea sandstone and Texas Cream limestone cores to quantify the loss in relative permeability caused by condensate accumulation. The in-situ condensate saturation was established dynamically by precise control of core inlet and outlet pressures. It is well known that retrograde condensate dropout can cause significant productivity loss in low permeability reservoirs. This paper shows that such losses can also occur in high permeability reservoirs. Gas relative permeability reductions of 91% to 97% were seen in 2-5 md limestone cores and 95% to 98% in 246-378 md sandstone cores. In light of the new data presented here, the common perception that condensate blocking around wells in high-permeability reservoirs is not significant should be re-examined. Our previous coreflood experiments showed that methanol treatments increased the gas relative permeability in low permeability carbonates, but we had not yet determined the required methanol treatment volumes as done in this study. Methanol displaces retrograde condensate and maintains improved gas relative permeability well into the post-treatment production period. Methanol also displaces water and this can also contribute to higher gas relative permeability in those cases when the initial water saturation is high enough to significantly add to the total liquid blocking of the gas. These results can be used to help reservoir engineers evaluate and treat gas-condensate wells with reduced productivity. Reservoir engineers should be especially careful to evaluate the damage done in such high-permeability reservoirs if the well's pressure drawdown is high enough to result in pressures below the dew point pressure.
A New Technique to Troubleshoot Gas Hydrates Buildup Problems in Subsea Christmas-Trees
Authors: Marques L. C. C. , Pedroso C. A. , Neumann L. F. 
Published: December 2007

Abstract
The paper is aimed at describing the series of actions taken to re-entry a well whose (wet) Christmas-tree-cap was clogged by hydrate buildup and therefore could not be released by means of a regular releasing tool. A deepwater well located in Campos Basin, offshore Rio de Janeiro, Brazil, was the scenario for this unique job. To our best understanding the kind of approach used to solve this hydrate problem has never used by industry before.
A patented thermochemical method – the so-called self-generated nitrogen (SGN) method–was applied to heat and dissociate the crystallized hydrate, which was clogging the tree-cap-locking-pin's piston chamber. Heat application around the body of the Christmas tree enabled us to dissociate the hydrate and release the tree cap by means of its regular retrieving tool.
This paper describes all the steps taken to perform this pioneer workover job. As a matter of fact, a multidisciplinary task that encompassed the following points: - development of a "tailor-made" environmental-friendly SGN formulation, - heat exchange simulations to design the optimum volume for the SGN treatment batch, - a review of the theoretical aspects of hydrate formation/dissociation, - mechanical modifications of the (regular) tree-cap releasing tool and, - a meticulous job and safe procedures review.
Challenges in Pigging of Subsea Gas Flowlines
Authors: Jayawardena Subash , Dykhno Leonid , Hudson John 
Published: December 2007

Abstract
Pigging is a common operation in the oil and gas industry. Pigging of flowlines is done with many objectives, including cleaning deposits such as wax layers, removal of liquids and flowline inspection. Pigging of gas flowlines in preparation for a restart of production after a flowline shut-in can provide challenges, as a significant amount of liquid may be left in the flowline. This liquid, when removed using a pig, accumulates upstream of the pig and moves towards the host facility during the operation.
This paper describes the challenges of gas flowline pigging. Gas flowline pigging initiated via a subsea pig launcher (in case of a single flowline) or from the host facility (in case of a dual or loop flowline) can be done using produced fluids. The major concerns are the subsea pig launching and control of pig movement, especially when pigging is done with produced gas. The factors affecting the dynamics of the pig and the produced fluids will be discussed. Special emphasis will be placed on discussing the challenges associated with the subsea pig launching required for single flowline pigging operations. The implications of these control challenges are also considered in light of pigging effectiveness.
Modeling experience of both single and dual (or loop) flowline configuration will be presented. The problems caused by hilly terrain as well as the steep risers leading to host platforms in deepwater subsea gas flowline systems will be discussed. Unless properly controlled, pigging of some gas flowlines results in unacceptably high pig velocities. Recommendations will be made on the optimization of subsea flowline pigging.
Energy Education: A Course for the 21st Century
Authors: Fanchi John R. 
Published: December 2007

Abstract
Energy demand is expected to grow this century as more countries seek a better quality of life for their citizens. The growth in energy demand will be met by a global energy mix that is undergoing a transition from an energy portfolio dominated by fossil fuels to an energy portfolio that includes a range of fuel types and energy conservation measures. This paper describes an Energy Engineering course for undergraduates that will increase the quality and quantity of engineering graduates as they embark on careers in the public sector and the emerging energy industry.
Project Valuation: Progressing from Certainty through Passive Uncertainty to Active Project Management
Authors: Chorn L. , Sharma A. 
Published: December 2007

Abstract
Investment opportunities with uncertain outcomes are the mainstay of the upstream energy industry. Valuation of these opportunities focus on the "invest / don't invest" decision. Companies have developed standard techniques to valuation to support this decision, but as more sophisticated techniques become available, managers and analysts stretch the standard to add more realism to the valuation.
This article presents a systematic study of valuation techniques. It begins with an investment problem, described by the expected value of key economic variables, which is properly valued by traditional discounted cash flow (Stage One). When the stochastic nature of key economic variables is included, it becomes necessary to increase the complexity of the analysis (Stage Two). The valuation evolves to a decision tree analysis, using a discrete representation of the distribution of NPV outcomes. As more granularity is included in the stochastic variable descriptions, Monte Carlo simulation is used to compute a continuous probabilistic NPV of the opportunity. Through stage two, the valuation process assumes management is passive in its ability to resolve the uncertainty in key economic variables. When an investment opportunity offers management the ability to resolve uncertainty before making an irreversible decision and management of the investment program is possible, the valuation process requires Real Options analyses techniques (Stage Three). As with Stage Two valuations, Real Options has discrete and continuous solution techniques for the valuation equation.
We compare the valuation provided by three techniques for the acquisition of a portfolio of maturing oil and gas properties. Through this systematic approach, the study provides a perspective for matching an investment opportunity with the appropriate analysis technique, based on the characteristics of the opportunity.
An Intelligent Identification Method of Fuzzy Models and its Applications to Inversion of NMR Logging Data
Authors: Finol Jose , Romero Carlos , Romero Pedro 
Published: December 2007

Abstract
In this paper we describe a novel approach to fuzzy model identification that gives solution to the inverse problem of permeability prediction from NMR data. The fuzzy logic approach uses fuzzy If-Then rules to establish the relationship between permeability (output variable) and the NMR T2 distribution mean values ϕNMR, ϕFF, ϕBF (input variables). We introduce an intelligent data-driven method that generates the fuzzy rules in a two-steps learning algorithm. In the first step, fuzzy clustering is performed on a set of input-output core measurements to obtain an initial approximation of the fuzzy rules in a rapid prototyping approach. This set of observations is the only information assumed about the model behavior. In the second step, the antecedent and consequent parameters of the identified fuzzy rules are fine-tuned by means of a gradient descent method. The identified fuzzy model is subsequently used to estimate permeability in uncored wells in the same field.
Computer simulations using data from a complex siliclastic sequence in the Maracaibo Basin (western Venezuela) show the advantages of this methodology over the conventional empirical and statistical inversion methods.
Why We Should Stop Using Pseudopressures and Other Good Old Well Test Interpretation Tools After So Many Years of Good Service
Authors: Houzé Olivier P. 
Published: December 2007

AbstractSome well test interpretation techniques still in use today were developed more than 30 years ago, to help the engineer at a time he/she (generally he) only had graph paper, a hand calculator and a set of printed type-curves. Unlike human beings, age is not a reason by itself to retire a technique. But, originally invented by paradigm breakers, thanks to our inertia some techniques have become paradigms themselves. They no longer bring anything, they confuse the learning of young engineers and worse, sometimes turn out to be incorrect and stand in the way of more rigorous and promising developments. It may be time to retire them from our industry, acknowledging what they brought us in the past. The author respectfully suggests to get rid of type-curves, pseudopressures1 and pseudotimes2. In each case, the author will try to explain why these tools were developed, why they were originally useful, but no longer. If the author survives this one, the following publication will deal with the Horner3 plot, equivalent time functions4 and deconvolution5. Otherwise there is absolutely nothing new in this paper.
Numerical Sensitivity Studies for the Joint Inversion of Pressure and DC Resistivity Measurements Acquired with In-Situ Permanent Sensors
Authors: Alpak F. O. , Torres-Verdín C. , Sepehrnoori K. , Fang S. 
Published: December 2007

AbstractIn-situ permanent sensors allow the possibility of monitoring in real time dynamic changes in formation properties due to primary or enhanced hydrocarbon recovery. A feedback loop can be enforced in response to in-situ permanent sensor data to optimally control the recovery of hydrocarbon assets. Prototypes of in-situ permanent sensors include pressure gauges, acoustic geophones, and direct-current (DC) resistivity electrodes.In the past, quantitative studies have been performed to assess the value of in-situ permanent pressure data to mapping permeability variations in close proximity to the sensor deployment1. Malinverno and Torres-Verdín2 on the other hand, have described a procedure to estimate water invasion profiles using in-situ DC resistivity sensors. However, to date little is known about the possibility of estimating petrophysical variables that jointly honor pressure and DC resistivity data acquired with in-situ permanent sensors. The two types of data sense different and complementary components of the underlying petrophysical model, and it seems appropriate to develop a quantitative estimation procedure that can assimilate the best elements of the two types of measurements. In this paper, we develop a methodology to jointly invert pressure and DC resistivity data acquired with in-situ permanent sensors in a hypothetical water injection experiment. Time-variable flow rates are enforced while injecting water into the surrounding rock formations, hence producing a sequence of repeated pressure pulses. The objective of the experiment is to estimate permeabilities, porosities, and fluid distributions that honor (a) sensor data acquired during a single pressure pulse, and (b) a more complete time record of pressure data acquired starting from the early stages of water injection. Our inversion results shed new light to the independent and joint sensitivity of noisy pressure and DC resistivity data to detecting dynamic perturbations of petrophysical properties. Examples of inversion are used to assess the relative benefits of different types of sensor deployments.
Downhole Fiber-Optic Multiphase Flowmeter: Design, Operating Principle, and Testing
Authors: Kragas Tor K. , Bostick F. X. , Mayeu Christopher , Gysling Daniel L. , van der Spek Alex 
Published: December 2007

Abstract
Real-time, downhole, multiphase flow rate data is widely acknowledged to be of significant value for production optimization. This is particularly the case for high-cost deepwater developments and in complex multi-lateral wells. Applications of downhole flow data include zonal production allocation, identifying and localizing production anomalies, direct determination of well productivity index, ability to commingle production from multiple zones, and reduction in surface well testing and facilities requirements. However, despite the potential value of this data, in the past reliable continuous measurements of downhole flow rates in producing wells have not generally been available because of difficulties in designing and deploying measurement devices for hostile in-well environments.
This paper discusses the design, operating principles, and flow loop testing of the world's first all-fiber optic multiphase flowmeter for downhole deployment. The flowmeter provides real-time measurement of flow rate, phase fraction, pressure and temperature. It is deployed with the production tubing and is rated to 125°C and 15,000 psi. It is full-bore, non-intrusive, has no moving parts, is electrically passive, and overcomes the design limitations imposed by downhole environments. Thus, it has the potential for providing highly reliable downhole measurements. The flowmeter has been extensively tested in Shell's multiphase flow loop in Rijswijk, The Netherlands over a wide range of oil and brine compositions and phase fractions, flow rates, and meter inclinations. Results from the testing have demonstrated the ability of the flowmeter to measure flow rates and water fractions in oil-water systems to within ±5% over the entire range of water cuts. These results have been validated by data from several field deployments.
Optimization of Production Operations in Petroleum Fields
Authors: Wang Pengju , Litvak Michael , Aziz Khalid 
Published: December 2007

Abstract
For some petroleum fields, optimization of production operations can be a major factor for increasing production rates and reducing production costs. While for single wells or other small systems simple nodal analysis can be adequate, large complex systems demand a much more sophisticated approach. Many mature fields are produced by gas-lift under multiple constraints imposed by the field handling capacity of the system. In this paper we present an optimization technique for allocating production rates and lift-gas rates to wells of large fields subject to multiple flow rate and pressure constraints.
The well rate and lift-gas rate allocation problem has been addressed in the literature1-13. However, existing methods are either inefficient or make significant simplifications. This often leads to suboptimal operations. This paper proposes a new formulation of the problem that is able to handle flow interactions among wells and can be applied to a variety of problems of varying complexities. We show that the proper formulation of the optimization problem is important in the practical use of modern optimization techniques. Once formulated, the optimization problem is solved by a sequential quadratic programming algorithm. Our results show that the procedure developed in this paper is capable of handling complex oil production problems.