bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wellbore-to-Fracture Communication Problems Pose Challenges in California Diatomite Horizontal Wells
Authors: Wright C.A. , Minner W.A. , Weijers L. , Davis E.J. , Golich G.M. , Kikuchi H. 
Published: December 2007

Abstract
In an increasing number of hydraulic fracturing environments, the petroleum industry has aimed for greater cost-effectiveness through the use of horizontal wells instead of conventional vertical wells. Several recent examples where this strategy has been evaluated include the giant Belridge oilfield where three horizontal wells have been drilled with an oblique orientation of roughly 700 to the preferred fracture orientation (determined by the existing well pattern), and completed with multiple propped fracture stages. In the past, industry has focused much attention on the connection between transverse hydraulic fractures and horizontal wellbores, primarily to avoid bridging screen-outs in the near-wellbore tortuous region. It was assumed that if the proppant could be placed successfully, then the fracture stimulation would be successful.
However, in the soft diatomite rocks in the San Joaquin Valley, a different problem has emerged. While premature screen-outs have not been a problem, the complex character of hydraulic fracture initiation in this rock has impeded the creation of a sufficiently conductive connection between the wellbore and the primary propped fracture(s). Integration of several diagnostic techniques (such as net fracture pressure analysis, tiltmeter fracture mapping, Hydraulic Impedance Testing (HIT), post-fracture production logging and video logging) reveals that the poor wellbore-to-fracture connection is due to the complex initiation of multiple hydraulic fractures along the horizontal wellbore, many of which are not effectively connected to the perforations. Despite appropriate far-field propped fracture penetration in the reservoir zones of interest, connection between the reservoir and wellbore is compromised because the main propped transverse fracture can be displaced 10 – 100 ft along the wellbore away from the perforated interval, This breakdown in wellbore-to-reservoir connection can severely damage well productivity, in extreme cases reducing individual stage contributions to zero. Figure 1 shows a conceptual sketch of what the actual fracture geometry induced from a single stage may look like. Note the small longitudinal fracture that runs along the wellbore and the many transverse fractures that leave the wellbore away from the perforated interval.
As petroleum production from transversely fractured horizontal wells has been successful in other environments, it is believed that the severity of the problems encountered with these wells was due the specific environment conditions (3D-stress state, rock properties, poor cement quality, etc.). However, these same problems are likely to occur, perhaps to a lesser degree, in many environments.
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A Procedure to Integrate Well Test Data, Reservoir Performance History and 4-D Seismic Information into a Reservoir Description
Authors: Landa Jorge L. , Horne Roland N. 
Published: December 2007

Abstract
This paper deals with the problem of estimating the distributions of permeability and porosity in heterogeneous and multiphase petroleum reservoirs by matching the dynamic behavior. The dynamic data is in the form of field measurements from well testing, production history, interpreted 4-D seismic information, and other data such as correlations between permeability and porosity, geostatistics in the form of a variogram model and the inference of large scale geological structure.
The issue was posed as an inverse problem and solved by using nonlinear parameter estimation. The procedure developed here is capable of processing all the information simultaneously and this results in a fast and efficient method. The procedure is also able to determine the uncertainty associated with the estimated permeability and porosity fields.
Examples of different parameter types that may be estimated by this approach include: (a) individual block permeabilities and porosities; (b) geological objects such as channels and faults; (c) pilot points that form the basis of a kriged distribution; and (d) seismic attenuation values from 3D seismic images.
An important conclusion of this work is that the value of each piece of information does not reside in its isolated use but in the value it adds to integrated analysis of the complete set of information. Thus data that traditionally was considered to be of low information content for reservoir characterization becomes useful and enhances the value of the data set as a whole.
Evaluation of Technologies to Treat Oil Field Produced Water to Drinking Water or Reuse Quality
Authors: Doran Glenn F. , Carini Frank H. , Fruth Darrell A. , Drago Joseph A. , Leong Lawrence Y. C. 
Published: December 2007

Abstract
Treatment technologies for reclaiming oil field produced water for beneficial reuse were evaluated, including thermal and membrane processes for salinity removal. Warm precipitative softening and high-pH reverse osmosis were selected for pilot testing based on a literature review of treatment technologies and results from bench-scale softening tests that indicated hardness, boron and silica removal could be simultaneously optimized.
EOS Simulation and GRNN Modeling of the Behavior of Retrograde-Gas Condensate Reservoirs
Authors: Elsharkawy Adel M. , Foda Salah G. 
Published: December 2007

Abstract
Currently, two approaches are being used to predict the changes in retrograde gas condensate composition and estimate the pressure depletion behavior of gas condensate reservoirs. The first approach uses the equation of states whereas the second uses empirical correlations. Equations of states (EOS) are poor predictive tools for complex hydrocarbon systems. The EOS needs adjustment against phase behavior data of reservoir fluid of known composition. The empirical correlation does not involve numerous numerical computations but their accuracy is limited.
This study presents two general regression neural network (GRNN) models. The first model, GRNNM1 is developed to predict dew point pressure and gas compressibility at dew point using initial composition of numerous samples while the second model, GRNNM2, is developed to predict the changes in well stream effluent composition at any stages of pressure depletion. GRNNM2 can also be used to determine the initial reservoir fluid composition using dew point pressure, gas compressibility at dew point and reservoir temperature. These models are based on analysis of 142 sample of laboratory studies of constant volume depletion (CVD) for gas condensate systems forming a total of 1082 depletion stages. The data base represents a wide range of gas condensate systems obtained worldwide.
The performance of the GRNN models has been compared to simulation results of the equation of state. The study shows that the proposed general regression neural network models are accurate, valid and reliable. These models can be used to forecast CVD data needed for many reservoir engineering calculations in case laboratory data is unavailable. The GRNN models save computer time involved in EOS calculations. The study also shows that once these models are properly trained they can be used to cut expenses of frequent sampling and laborious experimental CVD tests required for gas condensate reservoirs.
Application of Material Balance to Determine Ultimate Recovery of a San Juan Fruitland Coal Well
Authors: Zahner Bob 
Published: December 2007

Abstract
Volumetric methods to determine original-gas-in-place (OGIP) of coal bed methane reservoirs (CBM) are well established and documented. These methods differ from those used for conventional reservoirs in that they incorporate initial adsorbed gas content and/or methane isotherms to account for the fact that gas is adsorbed on the coal surface.
In practice, there are a number of factors which combine to create a great deal of uncertainty in volumetric calculations. Specifically, they are:Measurement of initial gas content is subject to several errors and frequently shows a wide variation within a given well. In many cases the only source of initial gas content measurement is from drill cuttings, which are known to give inaccurate results.Gas content may be derived from methane isotherms, but they require core and are typically available for only a limited number of intervals in a limited number of wells. There is often a wide variation in the character of these isotherms.Net pay is highly dependent on coal density. While density can be measured with logs, there is disagreement within the industry on what density cutoff should be used to determine net pay.In San Juan Fruitland Coal, CO2 content is often a high fraction of total adsorbed gas's and much greater than the produced CO2 fraction. Methane isotherms can be adjusted to account for CO2, but a pure CO2 isotherm is required, something which is difficult and expensive to obtain.
A material balance procedure proposed by G.R. King for coal seam reservoirs can be used to get independent OGIP estimates and can be programmed using a Lotus spreadsheet. If abandonment pressure is known, it provides a practical means for determining estimated ultimate recovery (EUR). Moreover, sensitivities can quickly be run to find the critical variables. An example of this process is presented for a well producing from the San Juan Fruitland Coal, including analyses of pressure transient tests to determine reservoir pressure. A cumulative frequency distribution of methane isotherms from San Juan Fruitland Coal is also presented. The results are compared to a history match with an Eclipse reservoir simulator.

Calculation of Original Gas in Place
The volumetric calculation of original gas-in-place (OGIP) for CBM wells is the sum of free gas in the fracture system and adsorbed gas on the coal surface. If initial water saturation is 100%, the volumetric calculation reduces to the following form:
where
OGIP = Original gas-in-place, Mcf
A = Drainage area, acres
h = Coal thickness, feet
Cgi = Initial sorbed gas concentration, scf/ton
d = Pure coal density, g/cm3
fa = Average weight fraction of ash
fm = Average weight fraction of moisture
Currently there are no methods to measure gas content in-situ and it must be inferred from indirect measurements taken from core or drill cuttings.
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Three-Phase Relative Permeability in Heterogeneous Formations
Authors: Paterson Lincoln , Lee Ji-Youn , Pinczewski W. Val 
Published: December 2007

Abstract
A percolation model is used to investigate three-phase relative permeability for displacements in porous media with spatial correlations. On a ternary plot, the region where the three fluids have non-zero relative permeabilities is notably larger for spatially correlated properties than for uncorrelated properties. When stratified bedding is introduced, the three-phase region increases when flow is parallel to the bedding, and decreases for flow perpendicular to the bedding. Relative permeabilities increase in a similar manner. These results show that spatial correlations have a significant effect on three-phase relative permeabilities and residual saturations.
Experimental Determination of the Mobility of Hydrocarbon Liquids during Gas Condensate Reservoir Depletion:Three Actual Cases.
Authors: Morel D. C. , Nectoux A. , Danquigny J. 
Published: December 2007

Abstract
The experimental results of three long core, low rate, reservoir condition gas condensate depletion tests are presented in this paper. The three cases exhibited very different PVT and rock properties. Early production of the condensed phase was observed, with CCS in the range of 0 to 6 %. Condensed phase recoveries varied from a few percent to 25% during these experiments.
The three tests were simulated with a compositional reservoir simulation model. Relative permeability needed to be varied with interfacial tension in order to represent the early mobility of the deposited condensed phase. The interfacial tension threshold below which miscible relative permeability begin to change was in the range of 0.5 to l dyne/cm.
The calculation of the inverse of the Bond number, involving rock and fluid properties, was a valuable preliminary tool to evaluate the possible mobility of the condensed phase, when maximum liquid deposit is lower than the black oil residual oil saturation.
Application of Neural Network Parameter Prediction in Reservoir Characterization and Simulation - A Case History: The Rabbit Hills Field
Authors: Ahmed T. , Link C. A. , Porter K. W. , Wideman C. J. , Himmer P. , Braun J. 
Published: December 2007

Abstract
Recent developments in artificial neural networks now make it possible to predict important reservoir parameters from combinations of well log, geologic, and surface seismic data. Our neural network predictions of porosity and permeability make use of high resolution 3-D seismic data and well logs to extrapolate these reservoir properties away from the borehole. These predictions can then be used for further geologic analysis, seismic interpretation, 3-D computer visualization, or input to reservoir simulators.
This methodology of integration of data types of different scales combined with prediction of reservoir parameters provides valuable feedback into the reservoir modeling process. This in turn enhances the capability of the reservoir team to model accurately subsurface detail and those features that are likely to control and influence the displacement processes associated with hydrocarbon production.
The NE Rabbit Hills Field, north-central Montana, USA, is used to demonstrate the use of this integrated reservoir modeling approach. Results of history matching using the neural network derived rock parameters are also presented.
Kick Detection in Floating Drilling Rigs
Authors: Doria M.T. , Morooka C.K. 
Published: December 2007

Abstract
Early detection of fluid influx from the formation into the wellbore during a drilling operation, generally known as a kick, is a major concerning for the safety of crew and rig equipment and, for the well itself. In the past, many well kicks have been observed at its very beginning by delta flow parameter which is simply the returned mud flow rate minus the circulating injected mud flow rate. Accurate flow measurements in this case are of great importance for the kick detection systems. When drilling from a floating rig, heave motion causes large instantaneous fluctuation in flow out from the well. It affects the delta flow measurement ant it is undesirable specially in deep water when kick detection is crucial. In the present work, many methods have been investigated as an attempt to overcome that problem. And, a new approach to obtain better delta flow indication is presented. Data has been recorded from a drillship in a real drilling operation. Discussions are carried out comparing the return flow rate of drilling mud onboard a floating drilling vessel and that obtained following the procedure here presented. Finally, a comprehensive state of the art is detailed and simulations of drilling operations illustrate an application with good results for identifying any delta flow change.

Introduction
The problems observed in the influx from formation in floating drilling units has be motivated a great effort from researchers in order to obtain more precisely the net flow rate between mud flow rate injected and returned from the well. Moreover, variations of mud tank level should be detected accurately with minimum effects of the floating rig motions. Particularly drilling vessel vertical heave motion causes undesirable fluctuations in the returned mud flow rate. The quick detection of an influx from the formation into the well is a one of the key point in the crew safety.
In the present paper, a method to identify the mud flow rate fluctuations induced by the drilling vessel vertical (heave) motion is presented. The main purpose is to detect the difference between the returned mud flow rate from measurements of a mud-logging unit onboard and estimated mud flow rate with fluctuations due to heave motion. In this manner, it is possible to have that differential on mud flow rate more clear and reliable in order to identify early gain or loss of mud flow rate from or into the formation. Any deviation observed on above mentioned differential which exceeds a fixed safety range is considered an abnormality of the well and stand by procedure for rig and crew safety must be taken. As an example, a simulation and a measurement of returned mud flow in a drilling operation are compared. Results showing simulated situations of loss and gain of mud in a drilling operation are presented.
Evaluation of Drill Bit Performance Taking into Account the in Situ State of Stress
Authors: de Castro F. J. N. , da Fontoura S. A. B. , de Albuquerque L. C. , Frydman M. , Dumans C. F. F. 
Published: December 2007

Abstract
The present paper describes a correlation between the bit performance and the state of stress acting upon the rock formation located immediately beneath the bottom of the wellbore. Bit performance data from 6 wells drilled offshore Brazil have been collected and analyzed. In order to reduce the empiricism associated with this type of data analysis, a study is being put forward that considers the geomechanical log along the drilled wellbore. The geomechanical log of a given rock formation is composed of its mechanical properties (Young’s modulus, Poisson’s Ratio, unconfined compressive strength, internal friction angle, etc.) as well as formation fluid pressure and in situ total stresses. The paper shows how to use these data to evaluate the stresses at the bottom of the wellbore through a 3D finite element program. Through these stresses it is possible to define an index of plastification ahead of the drill bit, and its performance is rated taking this index into account.
Some of the wells that are being analyzed were drilled in deep water locations, and the study shows a great potential for better understanding the reasons for good and bad performances regarding to the penetration rate of the drill bit in a rational manner. Based upon the analysis, a new study for drill bit evaluation will be put forward with the potential for great savings.
Viscosity Prediction of Natural Gases
Authors: Erdogmus M. , Adewumi M. A. , Ibraheem S. O. 
Published: December 2007

Abstract
Accurate prediction of thermal and transport properties of natural gases is very important in the design and operation of pipelines. Viscosity is one such property. This work presents an assessment of several theoretically based viscosity prediction methods. In this study seven natural gas mixtures are used. Comparison with experimental data shows the effectiveness of each model.
Progressive Technology Increases Flow Capacity in Horizontal Wells
Authors: Beall Brian B. , Tjon-Joe-Pin Robert , Brannon Harold D. 
Published: December 2007

Abstract
Many horizontal wells are drilled using the clean "drill-in fluids" introduced in recent years. The drill-in fluids are typically comprised of either starch or cellulose polymers, xanthan polymer, and sized carbonate or salt particulates. They were introduced to minimize the mud damage to the wellbore relative to that typically observed with conventional drilling muds. However, testing and experience have shown that insufficient degradation of the filter cakes resulting from even these "clean" drill-in fluids can significantly impede capacity at the wellbore wall. This reduced flow capacity can result in reduced well productivity or injectivity. Consequently, wellbore acid or oxidizer treatments are typically applied in attempts to remove or "bypass" the filter cake. These treatments are often only marginally successful, particularly when applied in extended length intervals. Formation damage, as well as filter-cake impairment, must be eliminated to realize the full potential of horizontal completions.
Previous laboratory studies have demonstrated that drill-in fluid filter cake can be effectively removed through the application of a newly developed technique incorporating an enzyme-based polymer degradation system.1 This treatment can be designed to degrade xanthan-based, starch-based or cellulose-based drill-in fluid. Following degradation of the specific polymer, the weighting and/or fluid loss control material is easily removed using smaller, less costly acid treatments.
Case histories of wells treated with the new enzyme technology compared to direct offsets treated with conventional acid or oxidative breaker treatments will be presented. Field experience has shown that through utilization of this new technology, smaller, less costly treatments can be used to treat openhole intervals to zero-skin potential with dramatically improved treatment efficiency. Production results have indicated that three-fold increases are possible when applying a two-stage enzyme/acid treatment to acid or oxidative treatments alone. Post-treatment production logs have indicated not only increased flow, but also flow throughout the entire openhole interval.
A New Approach for the Prediction of Rate of Penetration (ROP) Values
Authors: Bilgesu H. I. , Tetrick L. T. , Altmis U. , Mohaghegh S. , Ameri S. 
Published: December 2007

Abstract
Today applications of drilling require proper identification of operations where a cost reduction is possible. Many indicators are present when one tries to optimize the drilling operations such as casing size and mud properties. On the other hand the selection of the optimum bit requires information from a variety of sources. The parameters affecting the bit performance are complex and their relationship is not easily recognized. The general trend is to evaluate the performance of the bit from an offset well.
A new methodology was developed to model the rate of penetration and bit wear under various formation types and operating parameters. This method introduces a new approach with improved bit wear prediction. A simulator was used to generate drilling data to eliminate errors coherent to field measurements. The data generated was used to establish the relationship between the complex patterns such as weight on bit, rotary speed, pump rates, formation hardness, and bit type.
The method was tested using data from runs conducted with a rig floor simulator. The validity of the proposed method was also demonstrated with data from an existing field.
Riser Recoil During Unscheduled Lower Marine Riser Package Disconnects
Authors: Puccio William F. , Nuttall Reid V. 
Published: December 2007

Abstract
In the event of a deep water emergency disconnection, the sudden release of the Lower Marine Riser Package (LMRP) connector can cause the riser string to reach destructive velocities and displacements. Impact between the outer barrel of the telescoping joint and the diverter housing must be avoided.
Likewise, the LMRP assembly must lift a sufficient distance from the BOP stack to avoid impact due to oscillatory displacements caused by rig motion.
The objectives that must be met by any riser recoil system are to reduce the risk of damage to the LMRP, BOP stack, riser string, and substructure (with associated equipment), so that when the conditions that forced the emergency disconnect sequence no longer exist, operations may resume without delay.
This paper illustrates some of the significant variables affecting the velocity and displacement of the riser string and LMRP during an emergency disconnect sequence. The methods of controlling the emergency-disconnection process are reviewed.
Correct modeling of physical forces at work can assist in applying control mechanisms to increase the envelope of safe operation of a tensioner system equipped with a riser recoil system (Fig. 1).
A riser recoil test was conducted on an deepwater offshore drilling ship to test the effectiveness of the riser recoil control equipment, and to verify the model.
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