bluuebunny/crossref_metadata_2025_split huggingface dataset:
Verification of a 3D Hydraulic Fracturing Model Against a Field Case
Authors: Yamamoto K. , Gutierrez M. , Shimamoto T. , Maezumi S. 
Published: December 2007

Abstract
A three-dimensional simulator for the IOR hydraulic fracturing technique has been developed by the authors based on the theoretical coupling of fluid flow and fracture mechanics models. Heterogeneous formations of hydraulically-induced fractures such as non-planar curvilinear shaped fractures in a complex stress field and unsymmetrical fractures generated from deviated or horizontal boreholes are modelled using fully coupled modelling of fracture opening and injected fluid flow in the simulator. The hydraulic fracturing processes including the post-shut-in process are calculated so as to satisfy the equilibrium of injected fluid volume, fracture volume and leak-off volume. The models of physical phenomena, the fundamental algorithms and numerical techniques are introduced, and their applicability to the conditions of real field problems as well as the theoretical and numerical correctness and choice of the models are verified. The pressure history data during the injection and post shut-in periods obtained from fracturing in a North Sea field are used for the evaluation, with the formation model determined by wireline logging and empirical knowledge. The simulation results suggested the adopted fracture propagation criteria need to be reviewed. Nevertheless, history matching of the results of the bottom hole pressure between the numerical and real data confirms that the models developed by the authors can be used to estimate the geometry and extension during hydraulic fracturing.
Estimation of Reservoir Properties by Monte Carlo Simulation
Authors: Nakayama Kazuo 
Published: December 2007

Abstract
The shallow gas zone in the Pantai Pakam Timur (PPT) field, located in Northern Sumatra, Indonesia, has recently become an important target for development. However, only two wells were drilled in peripheral part of the field. In this situation the method of Geostatistics is hardly applied because of less control points, but there is a new suitable method to estimate reservoir properties under the condition of such few control points (GDI: Geology Driven Integration Tool). To compensate few controls, GDI creates pseudo-wells by Monte Carlo Simulation method with regional geological constraints in its regulation, and generates theoretical seismic traces from them. Then the suitable seismic attributes are selected after checking the proportionality with the given reservoir property. Finally the artificial neural network (ANN) is applied to detect the weighting factors, which relate the selected seismic attributes to the given physical reservoir properties. We apply this method to the 2-D seismic records in the PPT field to extract successfully the distribution of porosity and thickness of the gas sandstone reservoir. The most prospected area is figured out in the southern part of the field, where the net thickness of gas zone is estimated to increase 27 meters with fairly higher porosity of 28%, which can be fairly confirmed by the well proposed and drilled by this study. Once getting the distribution, it is easier to calculate the total rock volume of the target reservoir under non-homogenized situation, and hence to progress on estimating more precise volume of reserves in place. Thus this method has an advantage in estimating reservoir characters from a few well data in the early development stage, or even in the late exploration stage. It is certainly important for asset managing that new idea should save the cost even in the stage of exploration.
Accuracy and Efficiency Evaluation of EOS Computation Methods for Compositional Simulation
Authors: Honami Y. , Arihara N. , Yazawa N. 
Published: December 2007

Abstract
A field study by compositional simulation results in expensive computation by a huge number of phase equilibrium calculations. The common method of reducing the computation time is to describe the fluid by lumping its components into several pseudo-components. The main drawback of pseudoization is the loss of detailed compositional information on reservoir fluids.
This paper reports results of evaluation studies on accuracy and efficiency of different computing methods of equation-of-state incorporated in a compositional simulation model. The compositional model was formulated by the IMPES approach. The computation methods used for iterative EOS flash calculations are the successive substitution iteration (SSI) method, Newton method, their combination, and a generalized Michelsen method to reduce the number of independent variables.
Performances of the flash computation methods were evaluated by simulating behavior of a single well in gas condensate and volatile oil reservoirs, where the reservoir fluids were grouped into 5, 10, and 16 pseudo-components for each reservoir. Simulation demonstrated high effectiveness of the parameter reduction method showing significant decreases in flash computation time compared to the conventional methods, particularly when the number of pseudo-components was increased.
Non-Uniqueness of History Matching
Authors: Yamada Tomomi 
Published: December 2007

Abstract
A history-matched reservoir model cannot be unique, because the same production history could be fit by different reservoir scenario. This paper presents a field story where the risk arising from such non-uniqueness is highlighted.
The first history matching on the field was performed to understand its drainage mechanism. Interaction of gravity and viscous forces on vertically heterogeneous system clearly explained the production performance. Based on that finding, an infill program was proposed and was executed. The first well hit the remaining gas, but its productivity was less than expected. Spatial distribution of sand grain size was reviewed and it was presumed that the formation productivity at that location was originally good, but had been impaired over the production period. As the reservoir pressure had declined significantly, excessive permeability reduction due to rock compaction was suspected as the reason, for which no core data was available. The second simulation study was conducted to access that effect. The history was matched with different scenario than the first study and the location for the second infill was proposed, where an existing well happened to be producing from other horizons. Although its core obtained on the target zone suggested very high permeability even after compaction, the second infill turned out to be dry. The productivity impairment proved to be true, but permeability compaction was not enough reasoning for the dry hole. Underestimation of trapped gas saturation under overburden conditions was suggested by its well log, which was consistent with other evidence. The third history match was made and finally concluded that significant amount of gas was left, but as a non-continuous phase and therefore, was practically unrecoverable.
One must be extremely careful in the choice of reservoir parameters to be evaluated in history matching. Preparing more than one reservoir scenario will be preferred.
Interpretation of the Fluid Distribution and GOR Behavior in the Yufutsu Fractured Gas-Condensate Field
Authors: Ghorayeb K. , Anraku T. , Firoozabadi A. 
Published: December 2007

Abstract
The Yufutsu field is a new naturally-fractured reservoir in Japan with negligible matrix porosity and permeability. This large reservoir contains near-critical gas condensate fluids with unusual fluid distribution and production. The GOR shows a decreasing trend. This is perhaps the first report of such an observation in the literature. Another interesting and perhaps related observation is that measured data in some wells show the gas richness decrease with depth; methane increases while heptane-plus decreases with depth. Steady-state data from 5-km long wells at shut-in conditions show liquid in the middle, and gas in the top and bottom.
We used the expression of total diffusion flux (molecular, pressure, and thermal diffusion) to analyze and interpret the data in the Yufutsu field. One-dimensional and two-dimensional computations were performed using the Newton method and a new robust algorithm. Predictions were made in the entire reservoir using one single PVT sample in good agreement with data. Based on this work, it is concluded that thermal diffusion significantly affects the fluid distribution in the reservoir with consequence of decreasing the GOR produced.
The Japan National Data Repository: A Multi-User Database Challenge
Authors: Dent Logan , Kenji Akiyoshi 
Published: December 2007

Abstract
The Japan National Oil Corporation has constructed a National Data Repository to address the data management needs of both JNOC and the Japanese oil industry at large. Before this project, JNOC had difficulty managing the vast amount of data that it acquired each year. The costs associated with data management were large as well. Since the creation of the Repository, JNOC has been able to meet several goals. First, the secure and entitled storage of well and seismic data is ensured. Second, those data are more readily accessible by all potential users. Third, it has begun to unify the data management practices at JNOC, making them easier to maintain and define. It is also allowing users to go to a single place for all their data needs. Fourth, the project has reduced data management costs at JNOC and will do so for the Japanese oil companies as well. As part of its service to the local industry, JNOC is providing the NDR facility and expertise to all oil companies in Japan. This will allow them to reduce their data management costs, for both JNOC-sponsored projects and any others they choose to house at the NDR. The facility makes this possible by providing a fully entitled data store.
Evaluation of Cyclic Steam Injectors in China
Authors: Mao M. L. 
Published: December 2007

Abstract
For more than a decade, several fields in China have produced heavy oil from cyclic steam thermal operations. High temperature (650F) steam has been injected into the reservoirs. One field operates cyclic steam wells completed at 1600 meters in depth. This paper describes an innovative system to measure continuously, from surface to downhole, the pressure, temperature, and spinner responses in these steam injectors. Compelling data is presented to evaluate wellbore heat loss, steam injection profiles, and reservoir properties. A unique wellbore heat-loss model applies the measured temperature data to quantify downhole steam quality. Steam injection profiles have been obtained by analyzing spinner data against perforation intervals. During the steam soaking period, downhole pressure and temperature fall-off behaviors have been observed. The analysis of pressure fall-off curves yields wellbore skin and reservoir permeability. A new model to analyze temperature fall-off curves, by applying the Marx-Langenheim theory and a new set of type curves, yields heat transfer coefficients and steam swept zone size in the reservoir.
Performance and Evaluation Methods of Colloidal Dispersion Gels in the Daqing Oil Field
Authors: Lu Xiangguo , Song Kaoping , Niu Jingang , Chen Fuming 
Published: December 2007

Abstract
Polymer flood has been being used to provide a valuable tool for in-depth blockage of high permeability regions of the reservoirs in the Daqing oil field, where more than fifty thousand tons of polymers had been injected into reservoir for each year. But heterogeneity inside the reservoir is very serious in some areas and has caused channlling of polymer solution through high permeable zones, which not only wasted a lot of polymer but also affected the volumetric sweep.
The colloidal dispersion gels (CDG) were made up of low concentrations of polymer, aluminum citrate and additive in water, and combined with polymer solution during polymer flood for in-depth blockage of high permeability regions1,2,3. This paper provides a study of the performances and characteristics of the gels that were made up of aluminum citrate, produced water and polymer made in the Daqing oil field. The parameters used to evaluate performances and characteristics of the gels in laboratory include resistance factor, residual resistance factor, viscosity, elasticity, and polymer molecular texture and flood efficiency. The experiment results showed that the cross-linking reaction among a few polymer molecules or inside a molecule had taken place, which caused performance difference between the gel and polymer solution, and the best gels can be formed with a polymer: aluminum: additive S ratio of 100: 1: 25. The cost of the gels formed with the above-mentioned ratio was below 5 dollars /m3, which was almost the same as polymer solutions. According to these experimental results, two pilot test units with seven injection wells have been selected in the central part of the oil field, in which there are three central injection wells.
Prediction of Fracture Gradients in Samaan Field
Authors: Parriag E.R. 
Published: December 2007

Abstract
This study was undertaken to develop a correlation curve to show the variation of fracture pressure gradient with depth in the Samaan Field Offshore Trinidad. The method used to predict the Samaan formation fracture gradients is that of Ben Eaton. The results indicate that Samaan fracture gradients vary from 0.6 psi/ft at 1000 feet to 0.99 psi/ft at 12,000 feet.

Introduction
Fracture pressure gradients are necessary in designing casing and mud programs and help to avoid lost circulation problems while drilling. Fracture gradient has been shown to be a function of three independent variables, namely formation pore-pressure, overburden stress gradient and Poisson's ratio. In this study, each of the above three variables has been determined for the Samaan area and the resulting fracture pressure gradient curve has been constructed. pressure gradient curve has been constructed.

Prediction Methods
Several studies have been carried out to arrive at a method of predicting formation fracture gradients. Hubbert and Willis in 1957 and Matthews and Kelly in 1967 published papers outlining two different methods of predicting fracture gradients. Ben Eaton in 1969 developed a method which is modification of the Hubbert and Willis approach.

Hubbert and Willis Method
Hubbert and Willis used the following equation to determine fracture gradient:
(1) D D D 1-u D Pw = ( S − P ) ( u ) + P

(A) (B) (C)
Term (A) is the effective stress gradient, (B) is the horizontal to vertical stress ratio and (C) is the formation pressure gradient. Hubbert and Willis assumed that the over-burden stress gradient S/D was equal to 1.0 psi/ft and Poisson's ratio (u) equal to 0.25. Substitution of these values in equation (1)results in the following:
(2) D PW = 1 3 ( 1+2P ) PW = 1 3 ( 1 + 2 P )
However, these assumptions of Hubbert and Willis have been shown to be in error in many areas.

Matthews and Kelly Method
Matthews and Kelly presented a fracture gradient equation similar to equation.
P. 59
Flexible Drilling Tool May Aid In Enhanced Oil Recovery
Authors: Gourley Gary 
Published: December 2007

Abstract
A new tool in the industry may offer hope in regaining production from wells hindered by skin damage. A flexible drill string known as the Flex Tool was designed to drill a new well bore from vertical in order to get beyond the immediate perimeter of the well bore into new virgin territory. It can be run directly on the end of a work over string, without a motor, drilling a new well bore away from a kick off point adjacent to the pay at a slant approximately 15 feet from the vertical well bore allowing a new hole possibly horizontal into the target formation. If formation potential exist in this new well bore now beyond shallow well bore damage, it could offer hope for increased or regained production.
With economics in mind, this tool was designed to drill a short radius curvature for an operator seeking affordable alternatives to work over solutions. The ability to obtain a horizontal hole by an affordable means affordable makes the benefit to cost ratio extremely promising in some cases. This definitely put this tool on the list for the new millennium. this country has many older wells in need of work over solution to maintaining or regain production potential. An adjacent slant or horizontal well bore may be a great solution to overcoming the problems of abandonment. An experimental job near Graham, Texas will be discussed.
Have we Forgotten Oil is not Inert? Guidelines for Enhancing Stimulation Success.
Authors: King S. R. , Worley H. W. 
Published: December 2007

Abstract
Data bases, computer modeling and lower job costs have become the focus of stimulation treatment design. This focus has directed the attention away from well specific fluid testing and formulations. Fluids and additives for non proppant applications are often assumed to have equal performance and are compared only for cost. The value of fracturing fluids is often based on rheological properties and viewed only as a means to transport proppant. This line of thinking ignores potentially serious compatibility consequences in oil reservoirs.
Oil is not inert. The compatibility of treating fluids can enhance or impede production. Cold fluids can precipitate damaging high melting point paraffin. Acid treatments without adequate iron control, surfactants and/or aromatic solvents will sludge some crudes. Diesel has been shown to precipitate asphaltenes in some circumstances. This paper discusses testing and evaluation methods beyond conventional emulsion testing for cost-effective performance enhancement. Guidelines for testing, evaluating and enhancing stimulation treatments are presented with case histories.
San Andres and Grayburg Imbibition Reservoirs
Authors: Jerry Lucia F. 
Published: December 2007

Abstract
Residual oil zones several hundred feet thick are found beneath many San Andres and Grayburg oil reservoirs in the Permian Basin, West Texas, suggesting that these reservoirs once contained a much larger oil volume. Oil has migrated out of these reservoirs, causing the oil-water contact and the zero capillary pressure level (zcpl) to rise, placing the reservoir in imbibition rather than drainage mode. Therefore, saturation profiles should be characterized by the imbibition capillary pressure curve. Imbibition curves have lower water saturations in the productive interval and significantly smaller transition zones than predicted by drainage curves. The reduction in the transition zone is a function of the rise of the zcpl, which is equal to the thickness of the residual oil zone. A more accurate estimate of original oil in place can be obtained if imbibition curves are used to model fluid saturations.
Improving Economics of Production in Heterogeneous Reservoirs by Redirecting Water Injection Patterns
Authors: Prasad Rajan K. , Lake Larry W. , Jennings James W. , Lucia F. Jerry 
Published: December 2007

Abstract
Heterogeneous reservoirs undergoing waterflooding contain low-permeability zones in which oil in the low-permeability zones is bypassed by water. Profitability of producing from heterogeneous reservoirs can be poor because of premature water-breakthrough through high-permeability layers. It seems possible to improve the profitability of producing from heterogeneous reservoirs by diverting the injected water from preferentially flowing through high to low-permeability zones. The profitability improves because of a small increase in ultimate oil recovery and/or a large reduction in cumulative water production. The objective of this study is to investigate the applicability of the technology, referred to as indirect waterflooding, in different types of heterogeneous reservoirs.
We performed numerical simulations of waterfloods on a generic five-spot pattern for three different reservoir cases. The reservoirs had properties typical of a San Andres Formation. The first case, with vertical-heterogeneity, showed that ultimate oil recovery might be improved by up to 13% OOIP with indirect waterflooding. The second case, with areal-heterogeneity and a low kv/kh, showed that water production might be reduced by as much as 27%. The third case, with areal heterogeneity and a zero kv/kh, showed that water production might be reduced by 31%. Actual recoveries are sensitive to reservoir properties, especially in the magnitude of the vertical permeability.
Precision Pressure Measurement: The Key to Accurate Fluid-Interface Monitoring
Authors: Hannah P. M. , Vekved K. L. 
Published: December 2007

Abstract
In highly fractured reservoirs, where gravity dominated recovery processes are employed, fluid contact measurements and isobaric mapping are useful tools for understanding operational and process changes. Monitoring fluid contacts accurately in highly fractured reservoirs has always posed a challenge due to limitations in the measurement tools. Gradiomanometer surveys and electronic fluid property surveys lack the depth resolution needed to locate contacts, and direct measurement methods are time consuming, messy and yield no secondary information for quality control. Fluid gradient measurement is the desired method; but historically, limitations in gauge precision or thermal response have made this method unattractive.
An electronic pressure gauge using a silicon crystal sensor was shown to provide predictable response to strain under changing temperature and to provide the precision and accuracy needed for repeatable contact measurements and reliable pressure mapping. The pure silicon crystal has a small mass, a thin unbonded structure, and a temperature sensor for compensation placed in close proximity thereby decreasing the stabilization time required for true pressure recording. Rapid pressure measurement allows shorter, more frequent gradient stops; and consequently better data resolution for contact calculations.
Replacing non-pressure based contact measurement techniques in a field where bottom hole pressure surveys were taken on staggered intervals saved real dollars. This was done by adding one to two days onto a pressure survey and eliminating the separate contact survey. Measuring both contacts and pressures concurrently reduced time-normalization problems and increased data confidence. Accurate, repeatable pressure measurements clarified details of operational changes on the reservoir management process, improved the data collection process, and reduced expenses to the operator.