bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Design Approach for "Self-Lifting" Method to Eliminate Severe Slugging in Offshore Production Systems
Authors: Tengesdal J. Ø. , Thompson Leslie , Sarica Cem 
Published: December 2007

Abstract
Recently, exploitation of offshore petroleum reservoirs has moved to ever increasing water depths. Production from fields in water deeper than 1800 m is now a reality. The use of long deep-water risers that conduct production from multiple wellheads on the sea floor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. Considering the length of the deep-water risers, the problem is expected to be more severe than in production systems installed in shallower waters. Severe slugging could occur at high pressure, with the magnitude of the pressure fluctuations so large as to cause a shorter natural flow period with subsequent consequences such as premature field abandonment, loss of recoverable reserves and earlier-than-planned deployment of boosting devices.
In this study, a novel idea to lessen or eliminate severe slugging in pipeline-riser systems has been investigated. The principle of the technique is to transfer the pipeline gas to the riser at a point above the riser-base. The transfer process will reduce both the hydrostatic head in the riser and the pressure in the pipeline, consequently lessening or eliminating the severe slugging by maintaining the steady-state two-phase flow in the riser.
In this paper a steady state model is presented. It can be used as a design tool for the self-lifting concept by determining the operation envelope for successful self-lift operation given the location of the gas takeoff or injection points; it can predict the acceptable range of pressure losses in the gas bypass for continuous steady-state operation of the self-gas-lift system. The model was found to perform very well when compared to the acquired experimental data.
Effects of Pressure and Pipe Diameter on Gas-Liquid Two-Phase Flow Behavior in Pipelines
Authors: Abduvayt P. , Manabe R. , Arihara N. 
Published: December 2007

Abstract
The effects of pressure and pipe diameter on gas-liquid two-phase flow behaviors were investigated experimentally and theoretically for horizontal and slightly inclined pipelines. Experimental data of flow pattern, pressure drop and liquid holdup were acquired in the wide range of the gas and liquid flow rates in a large diameter (106.4 mm) pipe for different pressures (592 and 2060 kPa) and different inclination angles (0°, 1°, and 3°). To evaluate effects of the pipe diameter, our previous experimental data of low pressure (490 kPa) and small diameter (54.9 mm), were also used. Based on analysis of the experimental observations, a flow pattern map was developed for each pressure, pipe diameter, and inclination.
Major phenomena identified in data analysis include: Pressure and pipe diameter clearly affect the flow pattern transition boundaries. The high pressure tends to shift the boundaries to the lower side of superficial gas velocity in the flow pattern maps. In the large-diameter-pipe experemints, stratified flow was observed at higher superficial liquid velocities than in small diameter. The gas flow rate and inclination angle showed influences on liquid holdup and pressure drop behavior. The average pressure did not show large influences on liquid holdup and pressure drop.
Based on the experimental data, a mechanistic model was developed incorporating transition criteria for eight flow patterns, and individual flow models for estimating liquid holdup and pressure drop. The results predicted by the individual models demonstrated excellent agreements with the experimental data for each pressure and each inclination angle.
Shrinks or Quants: Who Will Improve Decision-Making
Authors: Begg S. H. , Bratvold R. B. , Campbell J. M. 
Published: December 2007

Abstract
Uncertainty is the underlying cause of the failure of many decisions to deliver their promised technical and economic metrics. Are these failures, despite the increased application of tools and processes for decision-making under uncertainty over the past decade, due to bad decisions or just bad outcomes? This paper examines quantitatively the validity of the assumptions underlying current decision tools and processes, and the extent to which their application accounts for the risks that arise from uncertainty. We also quantify the impacts of prevalent human biases and cognitive limitations on our ability to make decisions that are logically consistent with our objectives. We conclude that the above factors can have a large impact on the outcomes of decisions and therefore bad process, not just bad luck, is a major cause of disappointing results. More awareness is needed of the capabilities and limitations of common decision-making making techniques, and of the psychological and judgemental factors that influence their application.
Optimizing Multiple-Field Scheduling and Production Strategy with Reduced Risk
Authors: Cullick A. S. , Heath David , Narayanan Keshav , April Jay , Kelly James 
Published: December 2007

Abstract
Large, multiple-field Exploration & Production (E&P) assets require long-term commitments of capital that are tied to decisions on facilities, wells, scheduling, and production strategy. The decisions often must be made when there are high uncertainties, leading to risks. This paper presents a system which integrates finite-difference reservoir simulation, an economics model, and a Monte Carlo algorithm with a global optimization search algorithm to identify more optimal reservoir planning and management decision alternatives under conditions of uncertainty, such that the associated risks are managed. The optimization problem is posed with the business goals stated as a general objective function and includes all constraints (economic, reservoir, production, and statistical) that need to be honored.
The method is illustrated with an example of an E&P asset with multiple oil fields produced through a common surface network. The formulation of the example problem includes decision variables for the scheduling of reservoir units, the number of wells, and production rate capacities. It incorporates the nonlinear response of the objective to reservoir performance and surface pressure constraint through a flow simulator. The analysis is multi-period, evaluating the impact of predicted performance over time for each decision alternative. The individual reservoir units have uncertainties in hydrocarbon volumes and quality, reservoir deliverability, and costs. Decision solutions for objective functions of net present value (NPV) that mitigate risks are presented.
Design and Long-Term Production Performance of Frac Pack Completions in a Gulf of Mexico Deepwater Turbidite Field Having Inverted Sand-Shale Stress Contrasts: Case History
Authors: Shumbera David A. , Ellis Richard C. , Loya Darrell 
Published: December 2007

Abstract
Several sand control completions in the initial development of a Gulf of Mexico deepwater turbidite field failed prematurely when placed on production. After an extensive multi-discipline review of completion designs and procedures, the cause of these completion failures was determined to be an inverted sand-shale stress contrast, that is, shales were at lower minimum horizontal stress than adjoining sand layers. Direct evidence of this sand/shale stress reversal was obtained from mechanical strength property data derived from dipole sonic logs in two wells in this field.
Frac pack completion design was modified to account for this sand/shale stress reversal by incorporating perforation standoff from adjacent shales and by using smaller pad volumes. The modified design was successful in achieving excellent frac packs in seven subsequent completions in this field. Long-term performance of these modified frac pack completions has been excellent.
Sand Control Completion Reliability and Failure Rate Comparison With a Multi-Thousand Well Database
Authors: King George E. , Wildt Pat J. , O'Connell Eamonn 
Published: December 2007

Abstract
Through inter- and intra-company cooperation, an Excel database has been constructed with sand control reliability/failure information on over 2000 wells. The database makes possible the study of completion performance and the comparison of reliability for various forms of sand control, and common causes for sand control completion failures. This paper shares the general reliability results of this database without any reference to producing company name, service provider names or product names. The database contains information regarding general reliability and has information from many wells on cumulative production, maximum rates, drawdown, skins, pay deviation, screen length, and pay interval sorting, fines content, depth and length. The database is open to any company willing to share anonymous well data. There are no costs, no contracts and no meetings.
South Texas Hybrid Monobore High Pressure, High Temperature Well Design
Authors: Billa Rich , Gordon Doug , Watterson Ed , Mota Jose 
Published: December 2007

Abstract
Adopting tubingless and Hybrid Monobore well designs in the Fandango Field, Shell's most hostile high pressure, high temperature (HPHT) field in South Texas, has reduced drilling and completion costs by 30%. These designs and the cost savings they generate are allowing the development of the mature gas field to continue.
The tubingless design is now used in Fandango for wells with shut-in tubing pressures (SITP's) up to 11,000 psi. The Hybrid Monobore, a modified tubingless design, provides an additional pressure barrier and is run in wells with SITP's approaching 14,000 psi.
A Case Study of a Fine Scale Integrated Geological, Geophysical, Petrophysical, and Reservoir Simulation Reservoir Characterization with Uncertainty Estimation
Authors: Hamman J. G. , Buettner R. E. , Caldwell D. H. 
Published: December 2007

Abstract
A novel method for the integration of multi-scale rock and fluid information was performed on a single well deep-water exploration discovery. The method integrates diverse data types through physically constrained models into a single earth model. Development scenarios were optimized through multiple flow simulations. The development scenarios were designed to investigate the range of uncertainty in the earth model. This technique utilizes a single integrated earth model and multiple simulations in contrast to techniques that cannot reproduce the seismic, or reproduce the seismic but require a flow simulation for each geologic "realization".
The pending business decisions required reservoir characterization with the greatest precision possible and an understanding of the inherent uncertainties. The discovery was made based on 3-D seismic amplitudes, but a portion of the potential reservoir appeared to be obscured by a shallower seismic event. The available borehole data with which to construct the earth model consisted of conventional wireline logs and a wireline-conveyed formation tester from a single penetration. No flow tests, core or fluid samples were available.
The technique honors all the observed data through the alteration of an initial geologic model until, through up-scaling, an acceptable match is made with acoustic impedance determined from the observed seismic. The link between the geology and seismic is a rock physics model consistent with the well data.
The rock physics model is used to estimate the equivalent seismic properties from the porosity and fluid saturations in the fine scale geologic model. The objective is to minimize the difference between acoustic impedance generated from the 3-D seismic data and the forward-modeled very-fine scale geologic model. The uncertainties associated with each measurement and derived variables were assessed at each step. The resulting model will reproduce the original seismic amplitude data and all of the well data, although the well data were not explicitly used in the seismic inversion or the "inversion-of-the-inversion" estimation of petrophysical properties. Each cell in the resulting fine-scale geologic model contains porosity, permeability, and oil saturation.
The static model was up-scaled for dynamic flow simulation to estimate productivity and evaluate various development schemes. Numerous simulations were performed to address uncertainties in the geologic model and to account for risks associated with the geophysical imaging problems, and flow capacity. Two sets of distributions were assigned to porosity and permeability in the simulator for separate areas of the reservoir. A distribution was also assigned to fault transmissibility. The results of hundreds of simulator realizations were then used to estimate the range of uncertainty in reservoir performance under varied development scenarios.
Permeability Estimation Functions Based on Forward Modeling of Sedimentary Heterogeneity
Authors: Ringrose Philip S. , Skjetne Erik , Elfenbein Carsten 
Published: December 2007

Abstract
Effective permeability in the inter-well reservoir volume is notoriously difficult to estimate due to its scale dependence and sensitivity to heterogeneity. Using stochastic models of realistic 3D sedimentary heterogeneity at the 10cm to 10m scales, we established a series of functional relationships between effective permeability, bedding type and volume fraction (sand, mud, etc.). These functional relationships (bedding type curves) can be understood in terms of effective medium and percolation theory for mixed sand/mud systems, and are a significant improvement of conventional averaging procedures. The functions can be integrated with core plug and wireline data to give improved initial property estimates of the reservoir volume. We applied the method in field studies from several heterolithic reservoir formations of the Norwegian Sea. Improved estimates of vertical permeability are found to be particularly valuable for interpreting unexpected production data and dynamic reservoir history.
A Geostatistical Method for Characterizing Superpermeability from Flow-Meter Data: Application to Ghawar Field
Authors: Voelker Joe , Liu Jim , Caers Jef 
Published: December 2007

Abstract
This paper presents the application of multiple point geostatistical modeling, combined with a new technique for model perturbation, to characterize abnormally high flow capacity geologic features, super-k, within an 11-well study area in a large, Middle Eastern, carbonate reservoir. The reservoir characterization adequately history matches well flow-meter data measured in 2 surveys, taken over a 3 year period, obtained in 2 of the study area wells.
Characterization of the abnormal flow features is desired for future placement of water injection or production wells, to decrease the probability of wells being completed in the abnormal features, avoiding quick water breakthrough. The high conductivity features are an aggregation of two principle geologic components: high permeability beds of various lithologies, and high conductivity discrete fractures. These components form a flow network of unusually high conductivity, often much higher than predicted from flow capacity calculations in wells intersecting the network.
Simulation of flow in the discrete fractures is performed using well models. Well models offer several advantages over fracture discretization and dual porosity models, for flow simulations performed as part of an optimization algorithm.
A training image of facies architecture is developed based on conceptual depositional models of the reservoir. Using multiple-point geostatistics, various geologically realistic reservoir models can be generated, constrained to facies data from wells. Discrete fractures are associated with certain elements of the facies model, and therefore are added stochastically. A history match of flow-meter data is obtained with a single parameter optimization of the geostatistical model realizations, using a technique in which facies probabilities, rather than facies events, are perturbed. This method maintains integrity to the underlying geological model, while history matching, hence making prediction of future super-k occurrences possible.
A Novel Methodology to Derive the Dimensions and Degree of Containment of Waterflood-Induced Fractures From Pressure Transient Analysis
Authors: van den Hoek P. J. 
Published: December 2007

Abstract
It is well established within the Industry that injection of (produced) water almost always takes place under fracturing conditions. Particularly when large volumes of very contaminated water are injected –either for voidage replacement or disposal-large fractures may be induced over time.
The current paper aims to provide a methodology for Injection Fall-Off (IFO) test analysis of fractured (produced) water injection wells. Some essential elements of IFO for fractured water injectors are: Closing fracture, (early) transient elliptical reservoir fluid flow, finite fracture conductivity, and fracture face skin.
An exact semi-analytical solution is presented to the fully transient elliptical fluid flow equation around a closing fracture with finite conductivity, fracture face skin, and multiple mobility zones in the reservoir surrounding the fracture. This solution also captures the case that during closure the fracture is generally shrinking from adjacent geological layers under higher in-situ stress. Based on this solution, type curves of the dimensionless bottom-hole pressure as a function of dimensionless time are provided covering both the period during fracture closure / shrinkage and the period after fracture closure. The shape of these type curves is studied as a function of the different relevant parameters, in particular the fracture compliance, the height of in-situ stress contrasts, fracture face skin, fracture closure time, and injection period. It is shown how the fracture length and height, and the degree of fracture containment (in combination with the heights of the stress contrasts) can be derived from these type curves. It is also demonstrated that the analyses based on the storage flow and linear flow regimes need to be integrated into one analysis method in order to obtain consistent results.
Finally, the concepts developed in this paper are applied to a number of field examples, where the dimensions and degree of containment of the induced fractures are derived from the analysis of the IFO data.
Combined Use of X-ray CT Scan and Local Resistivity Measurements: A New Approach to Fluid Distribution Description in Cores
Authors: Durand Claudine 
Published: December 2007

Abstract
Continuous local resistivity measurements along a plug are combined with observations by CT-scan during the "plateaux" of a "steady state" procedure, as well as during "unsteady state" procedures at the end of the drainage or imbibition. This improves the consistency of the description of the experiment, allows the selection of the zones where the fluids are actually homogeneously distributed, and thus the quality of the RI-Sw relationship that can be drawn from these experiments, and which may be of paramount importance in the log interpretation. Identification of non-homogeneous zones can bring some ideas about mechanisms of fluid flow. Following a work on homogeneous Fontainebleau sandstones, examples are given on heterogeneous carbonates.
Effect of Fracture Conductivity on Effective Fracture Length
Authors: Lolon Elyezer P. , McVay Duane A. , Schubarth Stephen K. 
Published: December 2007

Abstract
Fracturing fluid that remains in the fracture and formation after a hydraulic fracture treatment can decrease the productivity of a gas well by reducing the relative permeability to gas in the region invaded by this fluid. This fluid can block the gas flow into the fracture, thus reducing the effective fracture length. Pressure transient tests performed on hydraulically fractured wells often reveal that the effective fracture half-lengths are substantially less than the designed length from fracture stimulation.
In this work we used reservoir simulation to determine the relationship between fracture fluid production, effective fracture length, and gas productivity. While the effective fracture length is affected by such factors as non-Darcy flow, it is related directly to fracture cleanup, and increases with time. From this study we found that the rate of fracture fluid production is affected significantly by the conductivity of the fracture. Greater dimensionless fracture conductivity results in more effective well cleanup, longer effective fracture lengths versus time, and greater effective stimulation of the well.
The results of this study provide a better understanding of the gas production behavior from wells hydraulically fractured using water-based fracturing fluids. The relationships between fracture conductivity, effective fracture length, and gas productivity presented in this paper can be used in economic calculations to balance the costs of higher fracture conductivity against the additional revenue resulting from longer effective fracture lengths. Results presented will allow operators to better design optimal fracture lengths for typical gas reservoirs.
Prediction of Gas Hydrates Formation With DSC Technique
Authors: Dalmazzone C. , Herzhaft B. , Rousseau L. , Le Parlouer P. , Dalmazzone D. 
Published: December 2007

Abstract
With the increasing number of deep offshore drilling operations, operators and service companies are now faced with new problems related to the possible formation of gas hydrates in drilling muds. Actually, the appearance of gas hydrate crystals in drilling fluids can lead to dreadful effects and safety problems, like modification of mud rheological properties, interruption of the drilling operations due to plugging and even destruction of rig equipment when gas hydrates dissociate. Propulsion of gas hydrate plugs at very high velocity is also a great risk. To prevent these problems, formulations of drilling muds (WBM or OBM) have to be optimized with thermodynamic inhibitors of hydrate formation (salts and glycols), which cause important problems of density adjustment, corrosion and toxicity.
In previous papers (SPE 62962, 71379), an innovative calorimetric technique (DSC) was presented to characterize hydrate formation in drilling mud up to 100 bar. This rapid, easy and reliable technique was applied to fluids of increasing complexity, from solutions and emulsions to complete oil-base and water-base muds. Results were validated from classical PVT measurements.
In this study, this work was continued on thermodynamic properties of hydrate formation in complex solutions. The main objective was to establish phase diagrams of ternary and quaternary mixtures (water-CH4-salt and water-CH4-salt-glycol) and also to understand the mechanisms that govern hydrate formation in such mixtures.
In parallel, a new microcalorimeter was developed, that allows measurements on gas hydrates up to 400 bar, whatever the mud composition (WBM or OBM). This apparatus can analyze complete muds, in presence of solids, and is designed to be implemented on drilling platforms. Hence, it will be possible to follow the risk for hydrates formation as a function of drilling conditions on site. Furthermore, this apparatus will allow the establishment of a database on different muds. A coupling of this database with a software that calculates the thermal profile along the riser should give birth to a predictive method for gas hydrate formation risks.