bluuebunny/crossref_metadata_2025_split huggingface dataset:
NMR Characterization of the Water Adsorbed by Montmorillonite: Impact on the Analysis of Porosity Logs
Authors: Chitale D. V. (Vivek) , Sigal Richard 
Published: December 2007

Abstract
Reservoir rocks contain interstitial pore water as well as the water adsorbed by the clay minerals. It was suggested by Chitale, et. al. (2000) based upon NMR characterization of montmorillonite that the threshold quantity of adsorbed water in this clay is 500 mg per g of dry clay, which agrees closely with the values reported in the clay science literature. This paper provides a summary of those aspects of hydration of montmorillonite that have direct bearing on log analysis and it highlights the impact of the optimization of amount of water adsorbed by montmorillonite on the interpretation of NMR-as well as conventional density and neutron porosity logs.
A new petrophysical parameter "wetness" is defined for montmorillonite as being the ratio of "volume of adsorbed water / volume of wet clay". A generic term "wetness-clay" applies to any clay. It computes to 0.57 for water-saturated montmorillonite. The wet clay density for montmorillonite available from the standard log interpretation charts (Halliburton, 1991 and Schlumberger, 1994) ranges between 2 to 2.7 g/cc. This paper refines the bulk wet clay density to 1.7g/cc for montmorillonite with a dry clay density range of 2.6-2.7 g/cc. It translates to an apparent wet clay density-porosity of 58%, which is a measure of the water adsorbed on montmorillonite surface. The refined value for thermal neutron porosity that measures both water and the hydroxyls in the clay is proposed to be 70%.
Rationalization of the wet clay-end-member values for the density, neutron logs based on the adsorbed water in montmorillonite should enhance the quality and accuracy of the overall log interpretation.
Fluid Identification and Pressure Transient Analysis in the Fractured Monterey Using the Modular Dynamics Tester
Authors: Grayson S. T. , Morris C. W. , Blume C. R. 
Published: December 2007

Abstract
The fractured Monterey formation of offshore California is estimated by the MMS to contain over one billion barrels of remaining reserves. Quantitative wireline evaluation in fractured reservoirs had been difficult in the past. Resistivity imaging using the FMI tool now provides the clarity to identify, orient, and quantify individual fractures. And recently, with the addition of the Modular Formation Dynamics Tester (MDT) tool, the fluid content of selected fractures can be positively identified while the tool is downhole. In addition, transient pressure analysis can be performed to reveal critical reservoir parameters. On a series of offshore Monterey wells, the FMI and MDT were used to identify and test fractures. The MDT was configured with the Dual Packer module in order to straddle-test fractured intervals selected from the FMI image. Tests were conducted to identify the fluid contained in the fractures, locate the reservoir gas cap, acquire pressure data, and take fluid samples. Perforations were confidently selected in the zones with the best quality fractures to maximize oil and to minimize gas production. Analysis of the buildup data provided formation pressure, permeability, and skin damage information. Comparisons of the fracture permeability with the corresponding resistivity image gave a visual calibration for enhanced image interpretation. Analysis of the formation pressures also provided an understanding of the hydraulic communication between different layers within the Monterey.
Overcoming Formation Damage in Heavy Oil Fields: A Comprehensive Approach
Authors: Tague James R. 
Published: December 2007

Abstract
Most heavy oil production occurs from shallow, unconsolidated sandstone reservoirs. Unfortunately, these reservoirs are prone to multiple forms of formation damage including sand and fines migration, clay swelling, organic precipitation, scale, and formation alteration caused by thermal EOR. In many cases, standard industry practices fail to remove or prevent this formation damage from occurring for a variety of reasons including improper identification of the damage mechanism and selection of inappropriate remedial or prevention techniques. This paper will present a comprehensive approach for optimizing production in heavy oil fields prone to formation damage. It will discuss the analytical methods used to identify and quantify multiple formation damage mechanisms, propose guidelines for remedial design, introduce some methods of statistical analysis used to determine optimal remedial treatments, and suggest some methods for implementing a field program for the remediation and prevention of formation damage. Overall, this paper should provide a useful methodology for improving production in any heavy oil field prone to multiple formation damage mechanisms.
Dry Forward Combustion with Diverse Well Configurations
Authors: Akin Serhat , Bagci Suat , Kok Mustafa V. 
Published: December 2007

Abstract
In situ combustion is a thermal recovery technique where energy is generated by a combustion front that is propagated along the reservoir by air injection. Most of the previously conducted studies report thermal and fluid dynamics aspects of the process. Modeling in situ combustion process requires extensive knowledge of reservoir data as well as reaction kinetics data. Unfortunately, limited kinetic data are available on the rates and the nature of partial oxidation reactions and the high-temperature combustion reactions of crude oils and their saturate, aromatic, resin, and asphaltene (SARA) fractions. Moreover, the impact of such data on the modeling of the in situ combustion process has not been investigated thoroughly. Thus, we modeled in situ combustion experiments conducted on a 3D semi-scaled physical model that represents one fourth of a repeated five spot pattern. In all experiments a vertical injector is employed whereas, both vertical and horizontal producers have been installed to recover two different crude oils (heavy and medium). Several locations for the producers have been tried while keeping the length of the wells constant: vertical injector-vertical producer, vertical injector-horizontal side producer, and vertical injector-horizontal diagonal producer. In these experiments horizontal side producers performed better than the others. We first simulated the experiments by incorporating a kinetic model that is based on grouping the products of cracking into six pseudo components as heavy oil, medium oil, light oil, two non-condensable gases and coke using a commercial thermal simulator (CMG's STARS). Seven chemical reactions were considered: cracking of heavy oil to light oil and coke, heavy oil burning, light oil burning, and coke burning. Most of the experiments were history matched successfully with the exception of ones where a diagonal horizontal producer was used. We then repeated the simulations using SARA kinetic parameters. We observed that all matches were somewhat improved. We finally present a discussion of application of the models to field scale.
How New Horizontal Wells Affect the Performance of Existing Vertical Wells
Authors: Shirif Ezeddin E. 
Published: December 2007

Abstract
Horizontal wells are reviving many marginal oil fields through accelerated oil production. In some fields, a single horizontal well produces as much as all the vertical wells put together. While there are prolific results as far as the profitability of the operation is concerned, there are other pertinent questions that arise. Does the vertical well flow pattern suffer as a result of horizontal well production? Does the ultimate oil recovery increase as a result of horizontal well operation? Given a pattern of vertical wells, can a horizontal well location be so chosen that the total oil production (and recovery) is maximized? These are the questions this paper attempts to address.
The results show that horizontal wells do indeed capture the oil in the drainage area of vertical wells. The extent of this "loss" depends on several factors. These include direction and allocation of the horizontal well within the drainage area, position of the horizontal well between the vertical boundaries, permeability anisotropy, net pay thickness, and oil viscosity. For a given pattern, there is a horizontal well configuration that maximizes the total production rate. The question of ultimate oil recovery is quite complex, and it may be said that in light oil reservoirs a horizontal well would tend to increase the ultimate oil recovery. Although it is concluded that, each of these factors ascribes to significant effects, it is the location of horizontal well that warrant the greatest effect on overall performance of vertical well.
A Method of Integrating Capillary Pressure and Relative Permeability Data Into a Full Field Numerical Simulation of Main Body "B" Reservoir, Elk Hills Field, California
Authors: Hampton Thomas J. , Singh S. P. 
Published: December 2007

Abstract
There are several major reservoirs within Elk Hills Field with a large dataset of capillary pressure and relative permeability data. Several major reservoir studies are underway to assist in the further development of this world class field recently acquired by Oxy. A fullfield simulation has been tasked to quickly enhance the reservoir management of upper Main Body "B" Reservoir.
The challenge is to have a representative reservoir description that efficiently utilizes the wide range and large data set that is available. This is needed to fully model this complex, layered, turbidite reservoir (Stevens sandstone in Miocene Monterey formation). Also needed, is the ability to integrate additional laboratory data as it becomes available since modern core has recently been obtained. Main Body "B" has 42 sets of Capillary Pressure (Pc) from 7 wells, 29 sets of relative permeability to water from five wells, and 19 sets of relative permeability to gas from four wells. The laboratory capillary pressure was obtained in brine, gas, or mercury fluids. Most of the data was obtained in the 1970's.
By using an emerging innovative SCAL software program, some of the major tasks performed were the following: prepare a database of special core analysis, perform quality control, effectively convert the measured data to consistent units and field conditions, generate Leverette J-function, calculate height of saturation plane above free water level, group multi-phase rock fluid data according to hydraulic flow units, transform laboratory data into "rock" curves for input into ECLIPSE simulator and automatically assign curves to grid cells. This feature resulted in significant time savings to Oxy in developing an integrated model of Main Body "B" Reservoir at Elk Hills, where many different flow units were observed. Further, the quality of reservoir description is significantly improved by using this tool. Also, as additional data becomes available, it can quickly be incorporated into the model. By improving the quality of the reservoir model, accuracy in development planning is expected.
Control of Lost Circulation in Fractured Limestone Reservoirs
Authors: Davidson Eric , Richardson Lee , Zoller Simon 
Published: December 2007

Abstract
Fractured limestone formations present a great challenge to the Well Engineer in the designing of oil/gas wells. In the upper hole sections it may be acceptable to cure severe lost circulation by judicious use of cement or other non-reversible treatments, but in the case of a fractured reservoir the use of such treatments is not acceptable due to the damaging nature of the treatment. In really severe cases of lost circulation the only option may be to drill ahead, accepting losses, and having in place a floating mud cap. This procedure, however, is far from ideal due to the many uncertainties that prevail during such operations.
This paper deals with experiences gained while drilling wells in a highly fractured, vugular limestone reservoir offshore Italy. The reservoir in this case is dominated by very low matrix porosity rock but has highly fractured and karst related vugular porosity. These fractures and vugs are the main producing and stock tank oil originally in place (STOOIP) containing elements. Therefore the permanent plugging of the fracture/vugular porosity is not an acceptable option in the cure of lost circulation. Previous operations were unsatisfactory; when a conventional drilling fluid was used to drill the reservoir lost circulation resulted which rapidly gave way to total losses. Attempts to cure the losses were unsuccessful and the well was drilled ahead blind with seawater with no returns.
The problem was addressed by developing and implementing a loss control strategy for a subsequent well. The approach used an unconventional highly shear thinning fluid as the ‘drill-in’ fluid, the intention being to use the highly thixotropic nature of the fluid to control the rate of loss in the first instance. As losses became more severe, two component, cross-linking polymer pills were pumped to seal the loss zones and restore circulation.
This staged approach for controlling the losses was highly successful. Several incidences of total lost circulation were encountered and cured with the result that 258 m of reservoir section were drilled and successfully evaluated.
The techniques developed and the lessons learned during this operation will be of interest to engineers working in areas such as the Timor Sea, the Australian NW shelf and various regions of Indonesia, where similar lost circulation problems are common.
Aqueous Foams for Underbalanced Drilling: The Question of Solids
Authors: Herzhaft Benjamin , Toure Abdoulaye , Bruni Fabrice , Saintpere Stephane 
Published: December 2007

Abstract
Among the existing non-conventional drilling operations, underbalanced drilling offers several benefits such as prevention of lost circulation and formation damage, increase of rate of penetration and reduction of differential sticking occurrence. In underbalanced drilling, the pressure of the drilling fluid is intentionally maintained below the formation pore pressure. Specific fluids are used in order to achieve underbalanced conditions: gas, mist, aerated mud or foam. Drilling with foam is very valuable due to its very low density coupled to its excellent cuttings carrying ability, but characterization of foam properties under drilling conditions is still incomplete and this could be an obstacle to the use of this technique by operators. This work is a part of a research program on drilling foams characterization conducted in collaboration between IFP and Totalfinaelf and focuses on the properties of aqueous foams when in contact with solids. The first part of the study deals with the incorporation of solids such as clays into the foaming liquid formulation; experimental measurements show that addition of swelling clay leads to very good stability properties without the necessity to add polymeric additive. Furthermore, clay addition provides good filtration properties with the formation of a filter cake, and this is important in case of accidental overbalanced condition during drilling operation. Lubricity properties of foam formulations were also characterized. The second part of this work is a characterization of the solid transport properties of aqueous foams. An experimental setup based on the weighting machine principle was elaborated. It allows the measurement of solids removal under various drilling conditions (circulating time and inclination angle, cuttings size and concentration). A new method for describing solids removal is proposed. Dimensionless numbers involving all the fluid parameters permit to describe transport properties and to bring out critical conditions. Extrapolating these numbers to the well could provide an evaluation of the critical parameters necessary to clean inclined and horizontal wells.
Improved Estimation of Hydrocarbon Reserves Using High-Definition Lateral Log Array Data in Vertical and Highly Deviated Wells
Authors: Frenkel M. A. , Zhou Z. 
Published: December 2007

Abstract
The conventional dual laterolog (DLL) instrument, providing valuable information on formation resistivities, has been used in the petroleum industry for many years. However, in many situations, physical limitations of the DLL (e.g., limited vertical resolution, poor radial resolution in the presence of deep invasion, incorrect readings due to the Groningen effect, artifacts occurring in deviated wells) do not allow the interpreter to obtain the required information. Moreover, DLL data interpretation is normally accomplished on a level-by-level basis (1-D), which may result in overlooking hydrocarbon-bearing formations, underestimation of reserves, and low confidence in the interpretation results.
Currently, when oil production originates in thinly laminated reservoirs penetrated by vertical or highly deviated wells, the DLL tool alone cannot satisfy industry requirements for accurately predicting formation resistivity. The new High-Definition Lateral Log (HDLL) tool was developed to provide high-resolution array resistivity measurements and overcome most of these shortcomings.
The HDLL array tool performs a detailed radial sounding of the formation to evaluate the drilling fluid invasion profile. The tool provides a high vertical resolution detecting thin beds up to a 9-in. thickness. The data does not suffer from the Groningen effect and borehole dip artifacts. The resistivity image of the formation around the borehole, delivered at the well site, provides information necessary to delineate permeable zones and supports immediate operational decisions. Application of 2-D/3-D inversion-based interpretation allows the interpreter to recover the true formation resistivity and thus more accurately delineate and estimate the hydrocarbons.
The scope of the paper is to briefly introduce the HDLL technology and present quantitative results of petrophysical interpretations derived by the application of conventional and array-type resistivity measurements.
Two case studies for vertical and highly deviated wells from Oman and the North Sea demonstrate the added value provided by the HDLL technology. In the presented cases, HDLL-based interpretations show not only improved delineation of the known reservoirs but also extra pay intervals overlooked by DLL-based interpretations. The hydrocarbon saturation derived with the application of HDLL data is higher than the hydrocarbon saturation derived by the application of the conventional petrophysical interpretation. Use of the entire data suite of array data provides a much higher level of confidence in the presented hydrocarbon estimates.
Well Test Analysis in Gas-Condensate Reservoirs
Authors: Gringarten A. C. , Al-Lamki A. , Daungkaew S. , Mott R. , Whittle T. M. 
Published: December 2007

Abstract
Published analyses of well tests in gas-condensate reservoirs when pressure drops below the dew point are usually based on a two-zone radial composite model, representing regions of condensate drop-out around the wellbore and of initial gas composition away from the well. Laboratory experiments, on the other hand, suggest that three different mobility zones could exist: (1) an outer zone away from the well, with the initial liquid condensate saturation; (2) a zone nearer to the well, with increased condensate saturation and lower gas mobility; and (2) a zone in the immediate vicinity of the well with high capillary number which increases the gas relative permeability, resulting in a recovery of much of the gas mobility lost from condensate blockage. This paper investigates the existence of this latter zone in well test data. An example of well test analysis is discussed, which illustrates the difficulty of identifying such a zone as, in many cases, build-up and/or drawdown data are dominated by wellbore phase redistribution effects. Where the three zones can be identified, data are analyzed using a three-zone radial composite model to yield a complete characterization of the near-wellbore effects, and in particular the knowledge of the various components of the total skin effect: mechanical skin; rate-dependent two-phase skin; and skin due to gas condensate blockage. The existence of the three zones and the results of the analysis are verified with a compositional simulator where relative permeability depends on capillary number.
History Matching Geostatistical Reservoir Models with Gradual Deformation Method
Authors: Le Gallo Y. , Le Ravalec-Dupin M. 
Published: December 2007

Abstract
This paper presents a new history matching methodology to constraint 3-D geostatistical reservoir model to well and production data. This methodology is a general inversion procedure based upon the gradual deformation method. It allows for constraining simultaneously petrophysical, geostatistical and reservoir parameters to dynamic production data.
The gradual deformation algorithm creates realizations, which evolve smoothly while preserving the global statistical features of the model. The deformation process is coupled with an optimization algorithm to automatically match production history. After validating the inversion process on synthetic data, we focused on real data. The inversion process involves up to fourteen parameters constrained through a fifteen-year production history. A coarse geostatistical model conditioned to rock-types and porosities observed at well locations describes the geological uncertainties. The petrophysical uncertainties are summarized within the permeability-porosity laws considered for the two dominant rock-types in the reservoir. The main reservoir uncertainties are the strengths of the edge aquifers and the critical gas saturations for each rocktype. The final match is obtained after several inversions and is quite satisfactory with respect to well pressure, oil and water flow rates.
Conditioning reservoir models to dynamic data - A forward modeling perspective
Authors: Srinivasan Sanjay , Caers Jef 
Published: December 2007

Abstract
In order to predict accurately future production performance, a reservoir model should reflect the actual patterns of permeability connectivity (flow paths and barriers). Information about such patterns of connectivity is carried by flow response data recorded at wells. However, the flow response data are influenced by many factors other than permeability connectivity such as boundary conditions and fluid property variations. This paper presents a neural network-based procedure for filtering the information related to the permeability field in flow response data. The flow response data is modeled as specific multiple point averages of permeability values in the neighborhood of the well. Such multiple point averages allow accounting for the spatial connectivity of the permeability field. The superiority of such multiple point averages over single point permeability averages for representing flow response data is demonstrated over several reservoir examples.
The ultimate quest is to integrate the permeability connectivity information contained in the flow response data into the numerical reservoir models. This amounts to ascertain that the permeability numerical models identify the previous multiple point averages. A Markov chain Monte Carlo simulation algorithm is implemented to perform this identification. Alternative equiprobable permeability fields are generated which, in addition to reproducing the production data, conform to a prior model for the spatial variability of the permeability field. The results demonstrate that flow simulation on the simulated permeability fields do indeed match historic well test data accurately. More importantly, future reservoir performance predictions are rendered more accurate.