bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Oil in Old Field: Growth of North Kadi Oil Field, Cambay Basin, India: A Case
Authors: Marathe U.G. , Mandal A.K. , Ahmed A. Elias 
Published: December 2007

Abstract
North Kadi oil field is a major oil producing field in North Cambay Basin, India. The field discovered in 1969 is producing from high permeability sandstone reservoir of Eocene age. This reservoir is operative under active aquifer suppert. The field has about 80 m maximum gross hydrocarbon column. Preferential movement of water along certain trends, early water cut and sand incursion are some of the production problems. Till date the field has produced about 20% of OOIP. Exceptionally excellent production performance of certain wells in the eastern flank of the field located close to oil-water contact warranted a relook into the available data for possible field extension. Analysis of water encroachment trends in pay sand KS-I coupled with production performance behaviour and detail structural mapping with the help of well and seismic data indicated possibility of presence of new culminations with adequate additional storage capacity. North Kadi field which was so far depicted as a big anticlinal structure of simple type, in fact is characterised by presence of multiple small amplitude culminations and troughs. Production performance of certain wells and water encroachment trends is indicative of more available drainage area than visualised earlier. The overall pattern is suggestive of prediction of new unidentified culminations. (nearer to the low axes) which are beyond seismic resolution: to be mapped. New pool extensions are identified integrating these observations. One such culmination was drilled and proved oil bearing on the eastern flank of the structure (after 27 years of production history). Confirmation of new areas by drilling would enhance existing OOIP of the field by 14%.
P. 495
The PY-3 Field: India's First Permanent Floating Production System With Multi-Well
Authors: Bryans R.A. , Feller M.D. , Harries P.G. , Chandra Kuldeep , Bhatt A.M. , Bhandari L.L. 
Published: December 2007

Abstract
The PY-3 field, located some 18km offshore Tamil Nadu in the Cauvery Basin in southeast India, was discovered by ONGC in 1988. The field which lies in license CY-OS-90/l was awarded to the consortium in the 4th exploration licensing round offered in 1991.
The appraisal of the PY-3 field has shown the structure to be complex from a subsurface perspective. The reservoir comprises moderate to low quality Cretaceous sandstones of the Nannilam Formation. The sands were deposited as debriflow deposits in a trough formed by basement highs to the east and west of the field. Laterally the reservoir exhibits significant variation in reservoir quality. Variations in the overburden stratigraphy, result in large velocity variations and hence difficulty in modelling the depth to top structure which does not exhibit closure in time.
These subsurface uncertainties have been accommodated by adopting a phased development. The initial phase of development activity commenced in 1996 with first production in 1997. The development comprises subsea wells tied back to a floating production unit. A total of four wells have been used to develop the field, two of which were re-entries of existing appraisal wells.
Further development of the PY-3 field, involving potential water injection or infill drilling, will be implemented depending upon early reservoir performance.
P. 505
New Interpretation Technique for Determining Minimum Miscibility Pressure by Rising
Authors: Srivastava Raj K. , Huang Sam S. 
Published: December 2007

Abstract
Minimum miscibility pressure (MMP) is an important parameter for assessing the applicability of miscible gas flooding for an oil reservoir. Slim tube studies have been routinely used for the purpose in the past. In the last decade, with the advent of the rising bubble apparatus (RBA), estimation of MMP by RBA for systems exhibiting vaporizing gas drives has become more common. However, the measurement by RBA for systems exhibiting condensing gas drive or enriched gas drive behavior has remained limited in the literature. This lack possibly arises from the difficulty in associating the observed bubble behavior for such systems with MMP value. This paper presents an interpretation technique for estimating MMP for systems which may not exhibit vaporizing gas drive behavior. This single bubble injection technique has been validated by comparing measured MMP results with a slim tube study and with an empirical correlation. It is also supported by values obtained for a multiple-bubble injection technique as suggested in literature and by consistency in results when the mechanism may change from vaporizing gas to condensing gas drive.
P. 553
Fuzzy-Grey-Element Relational Decision-Making Analysis & Its Application
Authors: Yong Qidong , Hu Yongquan , Xiao Fangchun 
Published: December 2007

Abstract
Oil-gas field development is a complicated system, and it is a difficult to make a decision of optimal development project. In this paper, a new method which is called fuzzy-grey-element relational decision-making analysis was proposed for evaluating and optimizing oil-gas field development project based on the fuzzy matter-element analysis combined with the grey system theory. Its gist is described as the fundamental element of project by the orderly three element group consisting of "a project, an index, whiten fuzzy-grey-quantity". This group is called the fuzzy-grey-element of project. The merits and demerits of various sorts of technical and economic indexes among the projects are considered comprehensively to appraise and optimize the development projects of oil-gas field, a good effect is acquired. A case study for optimizing gas development project in China showed that the result has a good agreement with practice. Therefore, this method is a general tool and can be used in other areas of petroleum, too.
P. 649
Effect of Acid on Resin Coated Gravel in Prepacked Screens
Authors: Evans Brian , Ali Syed 
Published: December 2007

Abstract
The oil industry has long been concerned about the effect of acidizing wells when prepacked screens containing resin coated sand are employed for sand control purposes. Fears of unconsolidating the prepack material have often led to no acid being pumped, or small volumes that are potentially ineffective at removing deep reservoir damage. Previous compatibility tests have been performed at static conditions, where a cured resin coated gravel plug was immersed into hydrochloric and/or HCl:HF acids, and then crushed to see if any resin was removed or weakened compared to an unexposed core plug. These tests were never conducted in a dynamic condition using actual prepacked screen models until now.
Laboratory tests were performed on several prepacked screens containing either 20-40 or 40-60 U.S. mesh-cured, resin-coated gravel. The types of prepacks tested were dual-screen, single-screen, and Slim-Pak™ screen designs. The objectives of the tests were to determine whether the resin-coated gravel was damaged during the acidizing phase of a gravel-pack completion and to compare the pressure drop in the prepacks. Initially, a baseline was established showing pressure drops at various flow rates while circulating 3% ammonium chloride (NH4Cl) brine through the system without a prepacked screen. After placing a prepack in the test fixture, a baseline was established for each prepack screen with 3% NH4Cl at 1, 2, 5, 10, and 21 gallons per minute. Prepacks were acidized with 50 gallons per foot 10% hydrochloric acid (HCl) followed by 100 gal/ft of 7½ HCl and 1½ hydrofluoric acid (HF); then 200 gal/ft 3% NH4Cl.
Continuous flow rate and differential pressure were recorded using a strip chart recorder connected to a turbine flow meter and a differential-pressure transducer. Each test was duplicated to verify reproducibility. After testing, each screen was cut open so that the resin-coated gravel could be examined.
Current Materials and Devices for Control of Fluid Loss
Authors: Ross Colby M. , Todd Bradley L. 
Published: December 2007

Abstract
Although the traditional fluid loss control systems used in high permeability completions have received considerable discussion in literature, most of the documentation reviews the application of individual systems only; little is provided on how to evaluate which method is best suited for a given situation. This paper briefly describes the various fluid loss control systems and gives guidelines on the factors that must be considered in choosing a particular system.
P. 683
Spatial Multribution - The Art of Multiple Attribution
Authors: Kumar Rajan , Patra S.K. 
Published: December 2007

Abstract
Oilfield data fall in several categories. If one were to study the field behaviour from seismic data acquisition stage through simulation in light of the other, one would be confronted with the highly daunting task of studying some data in the light of other, another chunk in conjunction with yet another and so on. Leave aside the actual data, the database structure itself can run in hundreds of tables and yet remain incomplete. So, the complexities involved are all too obvious. Every time database designs are looked upon from managerial points of view, and as they pass through different managers, a need to restructure them is felt. Different managers have different ways of looking at the data and different corners on which to lay stress upon. Understandably, in a multidisciplinary environment, if one were satisfied with the outputs, other would only be partly satisfied while there may be someone not at all subscribing to the ideas. This is where a strong need to create junction to cross roads is felt. But the questions are i) Is it possible? and ii) Is there a solution which respects all the disparities and brews them into a meaningful concoction? This paper attempts at suggesting some solutions.
P. 669
Water Injection in Water-Wet Fractured Porous Media: Experiments and a New Model
Authors: Terez Ivan E. , Firoozabadi Abbas 
Published: December 2007

Abstract
This study examines water injection in water-wet fractured porous media and its modeling using the Buckley-Leverett theory. New experimental data on water injection in Berea and Austin chalk matrix block(s) are presented. Water injection in Austin chalk with a permeability of 0.01-0.04 md and porosity of 5% results in about 20% recovery from the rock matrix.
In the second part of the paper, we use the Buckley-Leverett displacement in a dual-porosity model to simulate the the literature data as well as the experiments presented in the first part. A new model is devised for the simulation of water injection in fractured porous media. A major element of the new model is the multiplication of the transfer flux by the fracture saturation with a power of 1/2. This simple model can account for both co-current and counter-current imbibition and it is computationally very efficient. The results of the proposed model and the fine-grid simulation are in good agreement with the experimental data.
P. 21
Reviewing the Strategy of Steamfloods in a Dipping Reservoir
Authors: Mastmann M. , Fabel G. 
Published: December 2007

Abstract
Steamflooding is the preferred enhanced recovery method in several medium heavy oilfields located in northwestern Germany next to the Dutch border (Emsland area). BEB, PREUSSAG ENERGIE and WINTERSHALL began their first steamflood project in the Georgsdorf field in 1975, followed by similar projects in the Ruehlertwist, Emlichheim and Ruehlermoor fields.
In the Georgsdorf field operated by BEB, several steam-flood projects were designed as pattern floods in a variable dipping sandstone reservoir at a depth of 2300 ft. Standard practice is to inject the steam below the center of a dipping steamflood pattern. In this field however, steam injection near the center of the pattern with a temperature of 600 0F and a steam quality of nearly 100 % created problems in the updip producers. These wells often steamed out early in the life of the project. The wells had then to be produced at reduced rates with a maximum wellhead temperature of 212 F (government limitation). Incremental production was mainly observed in the downdip wells due to gravity effects of the steam condensate.
A joint team of geologists, reservoir. and production engineers from BEB and Preussag Energie was formed to evaluate the feasibility of future steamflood projects. This included a review of the performance of the existing projects with respect to the location of the steam injectors. The team recommendation was to locate future steam injectors updip at the top of the structure. By moving the location of the steam injector updip, calculations in comparison to existing projects indicated a significant improvement in the incremental steam/oil ratio. This technique is contrary to the standard recommended procedures.
P. 59
Results of the Injection Well Polymer Gel Treatment Program at the Rangely Weber
Authors: Hild G.P. , Wackowski R.K. 
Published: December 2007

Abstract
The Rangely Weber Sand Unit is a large CO2 miscible WAG flood located in northwestern Colorado. Conformance improvement has become the key operating strategy due to the maturing flood's associated natural increase in operating expense and declining oil production. Conformance improvement is defined as improving the vertical and areal sweep of the reservoir and is one of the few strategies that will reduce operating expense and allow for the recovery of additional reserves.
The many different technologies and techniques that have been deployed over the last decade to improve the conformance of the reservoir include: selective injection equipment, straddle packer assemblies, pattern re-alignment, cement squeezes, foam treatments, reduced half cylcle slug sizes, simultaneous injection, and polymer treatments. These attempts have met with varying degrees of success.
Recent efforts using large volume (10,000 bbl) polymer gel treatments to treat injection wells have been very successful. This success is attributed to the fact that these treatments effectively impact the deep reservoir problem. Past near-wellbore treatments were not effective at preventing flow in the high permeability matrix and fracture pathways believed to be responsible for poor sweep.
Results from 44 injection well treatments performed through mid 1997 are discussed. Individual treatment examples and full project economics are provided. Field modeling and forecasting to assess the impact of continued treatments over the next ten years is also included.
P. 93
A Successful ASP flooding Pilot in Gudong Oil Field
Authors: Zhijian Qu , Yigen Zhang , Xiansong Zhang , Jialin Dai 
Published: December 2007

Abstract
An ASP flooding pilot of close well spacing in Gudong Oilfield was conducted successfully. The producers appeared obvious responses to the ASP flooding. The ultimate oil recovery increased by 13.4% OOIP.
This paper describes the whole process of the ASP flooding and the analysis of the reservoir performance based on the injection/production data, single well tracer surveys, carbon/oxygen log, sealing core drilling and monitoring the properties of the fluids. By means of the numerical simulation, the distribution and characteristics of various fluids are demonstrated.
P. 107
Effect of Wettability on Oil Recovery by Near-miscible Gas Injection
Authors: Wylie Philip , Mohanty Kishore K. 
Published: December 2007

Abstract
Oil can become bypassed during gas injection as a result of gravitational, viscous, and heterogeneity effects. Mass transfer from the bypassed region to the flowing gas is dependent upon pressure-driven, gravity-driven, and capillary-driven crossflows as well as diffusion and dispersion. There exist a number of factors that influence these mass-transfer mechanisms, including gas enrichment, injection methodology, orientation of the mass-transfer region, water saturation, and wettability. The focus of this study is on the influence that wettability has on bypassing and mass transfer. Experimental results reveal comparatively less bypassing occurs in a strongly oil-wet sandstone than in a water-wet sandstone for gravity-dominated, secondary gasfloods. Mass transfer under oil-wet conditions is enhanced, as a result of oil-wetting film connectivity, over that of water-wet conditions, where water-shielding is significant.
P. 169
A Case Study in Scaleup for Multi-contact Miscible Hydrocarbon Gas Injection
Authors: Jerauld G.R. 
Published: December 2007

Abstract
This paper describes the strategy and results of scaleup done to simulate a multi-contact miscible hydrocarbon WAG injection process. To adequately model both oil recovery and solvent retention in WAG, one must model three-phase flow including gas trapping. Scaleup of the multi-contact miscible gas process is particularly difficult because of the very fine- scale structure of the gas fingers and the miscible front. The case studied is a heterogeneous mixed-wet reservoir with a transition-zone down to an underlying aquifer. The objective was to develop pseudo relative permeability curves and other parameters which are suitable for running in a full-field limited-compositional model with 3 hydrocarbon components.
Both history-matching and more systematic approaches were used to generate pseudo relative permeability curves which reproduced results of high-resolution, fully- compositional reference simulations, Dynamic pseudoization techniques were used to derive first guesses at pseudo relative permeability curves, but required further calibration to successfully reproduce finer-grid, fully-compositional reference simulations. In matching incremental miscible-gas oil recovery timing and solvent retention, varying three-phase water relative permeability was much more effective than varying the mixing parameter in the limited-compositional model.
The predictive capability of pseudos was tested for changes with respect to slug size, WAG ratio, and solvent enrichment. Pseudos derived for one pattern or cross-section were tested in other patterns or cross-sections. Pseudos worked well with respect to changes in WAG ratio, fairly well with respect to changes in solvent enrichment, and moderately well for changes in slug size. They were less robust with respect to changes in description.
P. 219
Integrated Phase Behaviour Modelling of Fluids in Reservoir-Surface Processes Using
Authors: Gozalpur F. , Danesh A. , Todd A.C. , Tehrani D.H. 
Published: December 2007

Abstract
Compositional reservoir simulation is widely used in the design of improved oil recovery (lOR) schemes, in particular for gas injection and gas cycling studies. An integrated modelling approach, using a single equation of state (EOS), to describe fluid phase behaviour and properties within the reservoir, flow lines and process facilities is an attractive option for reservoir management. Low computational times for flash calculations is an important element in compositional reservoir simulation. Grouping of fluid components reduces the computational time, but the approach is not suitable for the integrated modelling, where detailed compositional information on produced reservoir fluids may be required in the design and operation of fluid processes at the surface.
If binary interaction parameters (BIP's) are not used in an equation of state, the number of equations in phase equilibrium calculations will reduce to three, regardless of the number of components. This will reduce the computational time markedly. However, the current practice in the industry is to calibrate, or tune, EOS models against experimental data by mainly adjusting BIP's.
In this paper, based on the approach which avoids using BIP's, a rapid flash calculation method has been evaluated and its convergence has been improved for gas condensate reservoirs. To improve the EOS prediction within a wide range of temperature, the temperature dependency function of the attraction term () was also modified. A practical tuning method has been developed which is consistent with the proposed function. The presented integrated tuning method can be applied to match the experimental data of different types of fluids within wide ranges of temperature and compositional changes using any EOS. The reliability of the proposed method and the associated saving in computing time, in comparison with conventional methods, are demonstrated in this work for a variety of fluids.
P. 277
Water Shut-off Field Experience with a Relative Permeability Modification System in
Authors: Faber M.J. , Joosten G.J.P. , Hashmi K.A. , Gruenenfelder M. 
Published: December 2007

Abstract
The Marmul field in Oman is exhibiting a low oil recovery caused by the high oil viscosity (80 mPa.s) and the moderate to strong edge water drive. The poor mobility ratio has resulted in early increased water production through water channeling and coning. The technology evaluated to reduce the water production made use of a so-called relative permeability modifier system which was composed of a cationic polyacrylamide and the crosslinker glyoxal. This gel system reduces the relative permeability for water, while only marginally affecting the relative permeability for oil. The aim of a relative permeability modifier system is a decreased water production and potentially an increased oil production. The major advantages for such a system are that the treatment is bullheaded down the well and detailed information on the inflow performance is not required. This was advantageous for the Marmul field in which all the wells have been gravelpacked. Selection criteria were used to establish which wells would be treated and the final candidates were randomly located over the field. The treatment design consisted of the injection of three equal sized polymer/crosslinking stages with increasing polymer concentration. Five of the initially six treated wells showed a positive response to the gel treatment, i.e. (large) water-cut reduction and increased oil production. A simulation study on one of these treatments was performed to understand the behaviour of these treatments. Initial results could not match the observed field behaviour and only after introduction of flow barriers (shale layers) in the reservoir model a match between simulation and field could be achieved showing the significance of small details in local geology around the well. However, these flow barriers could not be seen on the open hole logs. Subsequently eight treatments have been performed. However, they were disappointing and no clear explanation for the deviating behaviour could yet be given. The causes for the poor performance could be poor candidate selection and/or a poor understanding of the gel system. Poor candidate selection is considered doubtful because the wells in the first six and the last eight treatments were randomly chosen throughout the field. Therefore, the emphasis is now on the gel system to determine more accurately its chemistry (e.g. polymer/crosslinker concentrations needed) and the volumes required to obtain an optimum result with respect to decreased water production and increased oil production.
P. 307