bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bidding Strategy: Reducing the "Money-Left-on-the-Table" in E&P Licensing Opportunity
Authors: Tavares Mario J. D. 
Published: December 2007

Abstract
When the results of Licensing Opportunities are analysed, one of the main features observed is the amount of "money left on the table". This is the difference between the highest (winning) and the second highest proposal presented in one specific tender. The objective of all investing companies should be to minimise this excess of money paid to win the tender, as it does not bring any benefit to the winner. An analysis of the Gulf of Mexico deep-water Lease Sales from Mar/97 to Mar/2000 revealed that companies left an excessive high amount of money on the table: an average of 42 to 63%. The 3rd Licensing Round in Venezuela and the 1st Licensing Round in Brazil were also assessed, revealing, respectively, 25% and 51% as the average money left on the table. Another important feature revealed in all these Licensing was that the money left on the table reduced as the number of competitors increased. By analysing all these issues, this paper proposes a strategy to increase the trade-off between thecapital invested to acquire areas and the overall expected value of the areas acquired. By following this approach, companies should avoid the excessive amount of money paid to win the tenders and still be able to acquire more area in the Licensing Round, if applicable.
Production Data Integration in Sand/Shale Reservoirs Using Sequential Self-Calibration and GeoMorphing: A Comparison
Authors: Wen X. -H. , Tran T. T. , Behrens R. A. , Gómez-Hernández J. J. 
Published: December 2007

Abstract
The stochastic inversion of the spatial distribution of lithofacies from multiphase production data is a difficult problem. It is so even for the simplest case addressed here of a sand/shale distribution and under the assumption that reservoir properties are constant within each lithofacies. Two geostatistically-based inverse techniques, sequential self-calibration (SSC) and GeoMorphing (GM), are extended for such purpose and then compared using synthetic reference fields. The extension of both techniques is based on the one-to-one relationship existing between lithofacies and Gaussian deviates in truncated Gaussian simulation. Both techniques attempt to modify the field of Gaussian deviates while maintaining fixed the truncation threshold field through an optimization procedure. Maintaining a fixed threshold field, which has been previously computed on the basis of prior information of lithofacies proportion data, well data, and other static soft data, guarantees preservation of the initial geostatistical structure. Comparisons of the two techniques using 2-D and 3-D synthetic data show that the SSC is very efficient in producing sand/shale realizations matching production data and reproducing the large scale patterns in the reference fields, although it has difficulty in reproducing small scale features. GM is a simpler algorithm than SSC, but it is computationally more intensive and has difficulty in matching complex production data. Better results could be obtained with a combination of the two techniques in which SSC is used to generate realizations identifying large scale features, then these realizations are used as input to GM for a final update to match small scale details.
Effect of Pore-Lining Chlorite on Petrophysical Properties of Low-Resistivity Sandstone Reservoir
Authors: Durand Claudine , Cerepi Adrian , Brosse Etienne 
Published: December 2007

Abstract
Chlorite bearing sandstones usually give low resistivity signals, and are thus erroneously identified as non pay zones, even if they exhibit good preserved porosities at depth. The purpose of the paper is to provide petrophysical and mineralogical laboratory measurements, that help improving the log interpretation in these sandstones.
The main results, obtained on a selection of reservoir cores, for sandstones having an amount of chlorite between 3 and 11 wt-%, are (1) the cementation index and saturation exponent (m and n) have values lower than the common 2 values, n frequently around 1.5. These low values have been carefully checked in order to avoid experimental artefacts. (2) Cationic Exchange Capacities (CEC) and Specific Surface Area (SSA) have low values, as expected from the clay structure. (3) the distribution of pore throats is bi or tri-modal, with a large contribution of microporosity.
The interpretation suggested by these results is that the amounts and distribution of microporosity associated to pore lining clay is the key of the chlorite sandstones electrical behavior. The values of CEC or SSA are too low to fully explain the low values of saturation index n.
Use of these low values in log interpretation has the effect of increasing the evaluation of oil in place. Advantages of a multi-disciplinary approach for better evaluation of such complex argillaceous sandstone reservoirs is highlighted.
Correcting for Wettability and Capillary Pressure Effects on Formation Tester Measurements
Authors: Elshahawi H. , Samir M. , Fathy K. 
Published: December 2007

Abstract
Conventional formation tester interpretation techniques have long assumed that the measured tester pressure is identical to the pressure of the continuos phase in the virgin zone of the formation. As such, a series of pressure measurements at different depths would be expected to consistently yield a pressure gradient corresponding to the density of the formation fluid. Recent work by the authors of this papers as well as by others has shown that the formation testers will actually measure the pressure of the continuos phase present in the invaded region, typically the drilling fluid filtrate. The measured tester pressure is, thus, different from formation pressure by the amount of capillary pressure. This capillary pressure has been shown to be a strong a function of the wetting phase saturation. The effects of the rock wettability and capillary pressure on wireline formation tester measurements are manifested as pressure gradient changes and/or fluid contact level changes on many logs, particularly those recorded with oil-based mud in the borehole.
This paper summarizes the effects of wettability and capillary on wireline formation measurements and investigates in detail the possible techniques for recognition and estimation of and correction for those effects. The older techniques rely on the use of core capillary pressure data log-computed flushed zone saturations, but they can often yield inconsistent results. Amongst the more innovative techniques suggested in this paper is the use of NMR measurements to estimate the magnitude of capillary pressure effects and hence correct the measured tester pressure. Also discussed in the use of the pump-out capability of the Modular Dynamics Tester (MDTTM) to estimate the capillary pressure effect by making measurements before and after the removal of drilling mud filtrate. This allows accurate correction for capillary pressure effects, or better still, the elimination of the need for the correction altogether.
Design, Implementation, and Analysis of Multilayer Pressure Transient Tests in White Rose Field
Authors: Coskuner Gökhan , Ramler Leon B. , Brown Murray W. , Rancier D. Wayne 
Published: December 2007

Abstract
The White Rose field is located in the Jeanne d’Arc Basin, lying some 350 km off the east coast of Newfoundland. The basin has proven to be the only area off the East Coast of North America with established major oil accumulation potential. The discovery well in the south area of the structure, the E-09, was drilled in 1988 encountering some 300 m continuous sand interval with an oil column of 135 m. Although there was a potentially significant amount of oil distributed in several fault blocks, the productive capacity of future development wells was uncertain based on the five conventional pressure transient tests conducted.
Following a 3D seismic program, a delineation program commenced in 1999 and three delineation wells were drilled geologically confirming over 600 MMSTB oil in place in the south. The wells were extensively cored and logged. Two sand intervals in the first well, the L-08, were tested using the conventional pressure transient testing technology. However, it was decided that a multilayer test (MLT) could be employed in the second well, the A-17, leading to significant cost savings when compared with conventional testing.
The A-17 well was logged to evaluate the formation as well as the cement bond. Four distinct pay intervals were observed and it was decided that the properties of these layers could be measured by conducting an MLT while also measuring the flow profiles with a Production Logging Tool (PLT). The test was successfully conducted and analyzed. Consequently, the rig time to test the well was reduced by at least 16 days, yielding savings of C$8 million. Given the success of the technique in the second well, the third delineation well, the N-30, was also tested using the MLT technique, again with significant cost savings. This paper discusses the design, implementation and the analysis of MLT's conducted in the A-17 and N-30 wells.
New Well-Testing Methods for Rod-Pumping Oil Wells — Case Studies
Authors: Guoynes John C. , Azari Mehdi , Gillstrom R. , Friend B. L. , Fairbanks M. D. 
Published: December 2007

AbstractA new well testing method that provides high-resolution bottomhole pressure measurement has been developed for use with rod pumping oil well completions. This new well testing technique is conducted by running a high-resolution downhole pressure gauge in a specially designed carrier assembly with the downhole pump. The gauge assembly is run on the rod string without pulling completion packers or tubulars. Using the new method, a downhole pressure system is in place while the well is flowing during the entire well test. High-resolution downhole pressure data can then be recorded during all flow and shut-in periods of the well test, which provides more accurate pressure data and enhanced capability for reservoir analysis.Traditional techniques use wireline-conveyed pressure gauges, tubing-conveyed pressure recording devices, and surface pressure monitoring systems with advanced fluid-level measurement to record data from pumping well completions. These methods are limited in their capability to provide accurate test results when low-pressure conditions prevail. The new method allows operators of low-pressure oil well completions to use advanced well-test analysis software to analyze actual pressure data to obtain reservoir properties and quantify skin damage. Data can be acquired from many types of rod-pump completions, including wells with downhole gas separators. Excellent pressure resolution has been obtained with this new testing technique using either of two downhole assembly designs, depending upon the completion configuration.The results and the ensuing well test analyses in several pilot pumping wells will illustrate that the new process permits more flexibility in well testing and allows for greater accuracy and better interpretation of data in low-pressure rod-pumping oilwells.
Fast and Robust Algorithm for Compositional Modeling: Part I – Stability Analysis Testing
Authors: Firoozabadi Abbas , Pan Huanquan 
Published: December 2007

Abstract
Given pressure, temperature, and composition of a fluid, one desires to determine whether the single phase state is stable. This problem is, in principle, much simpler than phase-behavior calculations. For certain applications such as compositional-reservoir modeling, stability testing can be the most important item for efficient phase-behavior calculations.
In this paper, we use the tangent-plane-distance (TPD) in the reduced space to perform stability analysis testing. The results reveal that there are major advantages in the reduced space. One interesting feature of the transformation is that the TPD surface becomes smooth and has one minimum. The combination of a single minimum and the surface smoothness contributes to a remarkable robustness in calculations.
Guidelines for Choosing Compositional and Black-Oil Models for Volatile Oil and Gas-Condensate Reservoirs
Authors: Fevang Øivind , Singh Kameshwar , Whitson Curtis H. 
Published: December 2007

Abstract
This paper provides specific guidelines for choosing the PVT model, black-oil or equation of state (EOS), for full-field reservoir simulation of volatile/near-critical oil and gas condensate fluid systems produced by depletion and/or gas injection.
In the paper we have used a "generic" reservoir from the North Sea containing a fluid system with compositional grading from a medium-rich gas condensate upstructure, through an undersaturated critical mixture at the gas-oil contact, to a volatile oil downstructure.
A component pseudoization procedure is described which involves a stepwise automated regression from the original 22-component EOS. We found that a six-component pseudoized EOS model described the reservoir fluid system with good accuracy and, for the most part, this EOS model was used in the study.
Methods are proposed for generating consistent black-oil PVT tables for this complex fluid system. The methods are based on consistent initialization and accurate in-place surface gas and surface oil volumes when compared with initialization with an EOS model. We also discuss the trade-off between accurate initialization and accurate depletion performance (oil and gas recoveries).
Each "reservoir" is simulated using black-oil and compositional models for various depletion and gas injection cases. The simulated performance for the two PVT models is compared for fluid systems ranging from a medium rich gas condensate to a critical fluid, to slightly volatile oils. The initial reservoir fluid composition is either constant with depth or exhibits a vertical compositional gradient. Scenarios both with saturated and undersaturated GOC are considered. The reservoir performance for the two PVT models is also compared for different permeability distributions.
Reservoir simulation results show that the black-oil model can be used for all depletion cases if the black-oil PVT data are generated properly. In most gas injection cases, the black-oil model is not recommended — with only a few exceptions.
We also show that black-oil simulations using solution oil/gas ratio equal to zero (rs=0) does not always define a conservative ("P10") sensitivity for gas injection processes. If gravity segregation is strong, the incremental loss of oil recovery due to "zero vaporization" is more than offset by exaggerated density differences caused by erroneous gas densities.
A New Rate-Time Type Curve for Analysis of Tight-Gas Linear and Radial Flows
Authors: Chen Her-Yuan , Teufel Lawrence W. 
Published: December 2007

Abstract
This paper presents a new set of Fetkovich type curves for production data analysis. The set extends early-time flow regime to include near-linear up to pure-linear flow, which are lacking in the original set. The proposed set is general but is particularly suitable for tight-gas wells due to the inclusion of the often-observed pure- and near-linear flow behavior. Theory of cross type curves between rate, cumulative production, and time is presented as well as the methodology of cross type-curve matching. Examples are given to show the applicability of the type curves for tight-gas evaluation.
Determination of Formation Properties From Stabilized and Unstabilized Gas-Well-Test Data
Authors: Tureyen Omer Inanc , Satman Abdurrahman , Onur Mustafa 
Published: December 2007

Abstract
In this paper, new explicit analytical equations for stabilized and transient deliverability coefficients in terms of formation/fluid parameters are presented. These equations are derived for fully and partially penetrating vertical wells and for fully penetrating horizontal wells. The proposed equations use the relationship between the empirical (Rawlins and Schellhardt) deliverability equation and rigorous (or Forechheimer’s) deliverability equations for both stabilized and unstabilized (transient) flow conditions. Based on these new equations, we also present new methods for determining not only the performance coefficients, but also formation parameters from stabilized and transient gas deliverability data. Unlike the existing methods, our new methods do not require geometric mean of pressure or rate data. This is a distinct advantage of the methods presented in this paper over the existing methods because determination of geometric mean of pressure or rate data may be quite difficult, and the mean value is quite sensitive to the measurement errors in such data. Thus, the methods given in this paper should prove very useful for determining formation parameters accurately from deliverability tests in vertical and horizontal wells. The accuracy and applicability of the methods given in this study are verified by analyzing two test data published previously in the literature as well as simulated test data. Results are compared with those obtained from the existing methods in the literature and indicate that combination of our new methods with the Hinchman-Kazemi-Poettmann method for isochronal test types provides more information about the formation and reliable deliverability forecasting.
Applying a Decision-Analysis-Based Method to the Evaluation of Potential Risk-Reducing Measures: The Case of a Floating Production Storage and Offloading Unit in the Gulf of Mexico
Authors: Lassagne M. 
Published: December 2007

Abstract
This paper presents an innovative methodology to evaluate risk-reduction measures applicable to an offshore installation, both from an economical and from a technical point of view and to help in choosing among them. The methodology notably addresses some of the most important weaknesses of traditional Cost-Benefit Analysis. Although it requires a more important involvement of the concerned parties than is the case for Cost-Benefit Analysis, we show that it may help to better evaluate and to select risk-reducing measures. After explaining some theoretical aspects, we present an ongoing application to FPSO risks and the expected results of this study.
Optimum Underbalance for the Removal of Perforation Damage
Authors: Walton Ian C. 
Published: December 2007

AbstractIt has been estimated that the permeability of the damaged zone around a perforation tunnel is reduced to approximately 20% of the original rock permeability. Since the perforation tunnel is the conduit for all produced fluids into the wellbore, removal of some or all of this damaged material is critical to the success of a perforated completion. Underbalanced perforating is regarded as the most efficient method of removing this damage.The degree of underbalance required to generate efficient perforations is still subject to much debate. Several guidelines have been produced in recent years, all of which calculate the optimum underbalance in terms of the permeability of the matrix (and fluid and tunnel parameters). All agree that the optimum underbalance should fall with increased permeability, but there is a great discrepancy in the specific relationship proposed. Most of the data on which the correlations are based and the models are validated comes from experiments on rocks with permeabilities in the 100–200 md range; extrapolation to lower and higher permeabilities is dangerous.In contrast to published models, we propose in this paper that underbalanced perforating promotes productive perforations by initiating mechanical failure of the damaged zone. A method is developed which predicts the optimum underbalance in terms of the strength of the matrix, the strength and extent of the damaged zone and the imposed stress conditions. Comparison with the results of single-shot perforating experiments lends support to the theory.
Perforation Damage Studies in Unconsolidated Sands: Part II - Baseline Studies and Comparison of Analytical Methods for Quantifying Damage
Authors: Snider P. M. , Benzel W. M. , Barker J. M. , Leidel D. J. 
Published: December 2007

Abstract
Traditional API Recommended Practice 431 Section 1 test of a gun system is focused on determining the perforation characteristics from the point of view of a perforating gun fired into rock of significant unconfined compressive strength. Entrant hole size and depth of penetration are the key parameters measured to demonstrate the gun system performance. These parameters do not tell how the energy of the penetrating jet is dissipated in the formation nor do they characterize flow from the formation through the perforation. The API Section 4 test is a means of producing the information desired, flow characteristics of the rock after perforating. These tests are expensive, long and difficult.
Furthermore, the API Recommended Practice 43 does not include a test method for evaluating perforators used in unconsolidated sand formations, but only simulates perforation in competent rocks. However, in unconsolidated sands, the guns do not produce a "tunnel or cavity" in the sand. Rather, the perforation path is filled with crushed sand and debris that strongly influence the flow properties of the perforation and requires characterization.
Two years ago the authors presented data showing a simple sand filled clamshell target could provide useful information for the development and design of shaped charges for unconsolidated sand. Suggested here is a standardized test method for a target focused on measuring the gun performance from the viewpoint of the formation while retaining the gun system performance parameters and developing a correlation between perforation path damage and perforation flow characteristics.
4D Cause and Effect: What do reservoir fluid changes look like on seismic?
Authors: Khan M. , Waggoner J. R. , Hughes J. K. 
Published: December 2007

Abstract
While most reported 4D effort focuses on 4D processing and interpretation of 4D seismic results, perhaps it is time to look at the problem the other way around. What 4D results are likely to arise from common reservoir depletion and displacement conditions? By better understanding the engineering cause of the geophysical effect, it may be possible for engineers to better contribute to the processing and interpretation of 4D data.
This paper looks at this issue through reservoir simulation studies. The reservoir simulator is a powerful tool to predict how fluid saturations and pressures are distributed throughout the volume of the reservoir over time. This information can be used in conjunction with a properly scaled rock physics model to generate seismic attribute maps that reveal the patterns of 4D results that would be expected under various depletion, displacement, and heterogeneity conditions.
The preliminary findings of this work are that pressure effects do obscure fluid saturation changes and exacerbate the effects of porosity variations in the reservoir. In addition, it is shown that care must be taken to accurately represent the poor vertical resolution of surface 3D seismic to avoid overly optimistic predictions of likely 4D seismic results.