bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Pulsed Neutron Capture Logging With Slim Carbon-Oxygen Tools: Methodology
Authors: Plasek R. E. , Adolph R. A. , Stoller C. , Willis D. J. , Bordon E. E. , Portal M. G. 
Published: December 2007

Abstract
Recently, two new slim through-tubing carbon-oxygen tools were introduced and described in the literature. In addition to carbon-oxygen water-saturation capability, these new instruments can provide, during the same trip, pulsed neutron capture (PNC) measurements (formation sigma, porosity, borehole fluid salinity, etc.). The answers have improved accuracy and precision compared to prior logging instruments. This paper describes the Dual-Burst* PNC measurement scheme for the RST* Reservoir Saturation Tool, as well as the algorithm methodology for determining corrected sigma, porosity, borehole fluid salinity, log quality and other associated outputs. Also documented are database measurements on which the algorithms are based, accuracy benchmarks in industry-standard calibration facilities, and precision (repeatability) comparisons. Log examples are presented.
Diffusion, borehole and lithology effects must be considered when transforming observed quantities such as decay times or near-to-far ratios to actual physical quantities. However, these effects are difficult to account for in direct analytical approaches over the entire range of oilfield conditions. Therefore, a multidimensional dynamic parameterization technique, based on an extensive set of laboratory measurements, has been developed and refined. This technique keeps the order of parameters low, resulting in a well-behaved response both inside and outside the range spanned by the database. The supporting database for each tool includes over 1000 measured points augmented with approximately 400 modeled points spanning different lithologies, porosities, borehole sizes, casing sizes and weights, formation fluid salinities, and borehole fluid salinities typically encountered in the oilfield.
Also reported are the sigma and porosity accuracy benchmark measurements made in the industry-standard calibration facilities (EUROPA facility, Aberdeen, Scotland and API test pits, University of Houston, Houston, Texas, USA). Precision (repeatability) is also compared to prior PNC logging instruments, demonstrating logging speeds typically several times faster for comparable precision.
An Application of Categorical Indicator Geostatistics for Facies Modeling in Sand-Rich Turbidite Systems
Authors: Jordan Douglas L. , Goggin David J. 
Published: December 2007

Abstract
A case study is presented in which a two-stage stochastic modeling approach was employed for modeling heterogeneities in a deep-water Gulf of Mexico field. The hydrocarbon-bearing intervals of this field were deposited as turbidites and exhibit high net sand/gross interval (net/gross) ratios.
In the first stage, a new facies indicator geostatistical method was used to model uncertainties associated with facies maps derived from seismic amplitudes. The concept of pseudo-wells is introduced for capturing geologic features and constraining the stochastic realizations. In the second modeling stage, synthetic stratigraphic columns based on whole core descriptions were used to capture fine-scale heterogeneities in cross-sectional panels. These cross-sections were subjected to flow simulations, yielding scaled-up values of single and two-phase flow parameters. Results from both stages were combined into a full-field 3-D reservoir simulation model.
Integrated Reservoir Description and Flow Performance Evaluation: Glenn Pool Field – Self Unit Study
Authors: Asnul Bahar , Thompson L. G. , Kelkar Mohan 
Published: December 2007

Abstract
This paper presents the study of an integrated approach to reservoir description as a part of the DOE-Class I Projects to improve the oil recovery from a mature oil field. The field selected is the Self Unit of the Glenn Pool Field that covers 160 acres. An integrated reservoir description was constructed which honors the geological, geophysical, and engineering data using geostatistical (stochastic) as well as the deterministic models. The description was validated by comparing the simulated results with static (well log and well core) as well as dynamic (well test) information.
Both stochastic and deterministic models replicate the geological model very well. The deterministic model predicts an optimistic performance, whereas the stochastic model follows the field data much better. The incorporation of geophysical information, taken from tomography surveys, improves the reservoir description when comparing with the observed well test information.
Using the description from each of the models, the flow simulations were conducted to match the historical performance and to predict the future production. Based on the flow simulation and the economic analysis, the plan of recompleting the wells along with an increase in the injection rate is found to be the most feasible solution to improve the performance of the Self Unit. The preliminary results from the implementation of this plan indicate expected results.
Field Development Planning Using Simulated Annealing - Optimal Economic Well Scheduling and Placement
Authors: Beckner B. L. , Song X. 
Published: December 2007

Abstract
A method for optimizing the net present value of a full field development by varying the placement and sequence of production wells is presented. This approach is automated and combines an economics package and Mobil’s in-house simulator, PEGASUS, within a simulated annealing optimization engine. A novel framing of the well placement and scheduling problem as a classic "travelling salesman problem" is required before optimization via simulated annealing can be applied practically. An example of a full field development using this technique shows that nonuniform well spacings are optimal (from an NPV standpoint) when the effects of well interference and variable reservoir properties are considered. Examples of optimizing field NPV with variable well costs also show that non-uniform wells spacings are optimal. Project NPV increases of 25 to 30 million dollars were shown using the optimal, non-uniform development versus reasonable, uniform developments. The ability of this technology to deduce these non-uniform well spacings opens up many potential applications that should materially impact the economic performance of field developments.
Hydraulic Fracture Stimulation of Highly Permeable Formations: The Effect of Critical Fracture Parameters on Oilwell Production and Pressure
Authors: Mathur A. K. , Ning X. , Marcinew R. B. , Ehlig-Economides C. A. , Economides M. J. 
Published: December 2007

Abstract
Hydraulic fracturing of moderate to high-permeability reservoirs with short, highly conductive fractures is a technique often applied to improve well productivity through penetration beyond near wellbore damage. This paper investigates the effect of important fracture parameters (e.g., fracture half-length, fracture conductivity, and fracture-face damage) on the short-term behavior and long-term productivity of the well. The degree and extent of near wellbore damage, in addition to the fracture parameters, are varied in the sensitivity analysis. A case study from the Gulf Coast addresses the effect of these important parameters on the well response.
It is evident the length and conductivity of a created hydraulic fracture have an important effect on the poststimulation performance of a well. Some of these fractures may be damaged. Damage to the proppant-pack has considerable effects, reducing the fracture conductivity. Generally fracture-face damage caused by fluid and polymer leakoff does not significantly alter long-term production, assuming the permanent reduction of absolute permeability is low (less than 90%) and provided the fracture bypasses the radial ldamage zone in the formation. When the fracture face damage is high (greater than 90%), early time well response is significantly impaired by the fracturing fluid cleanup process. This has implications on the timing of poststimulation pressure transient analyses. The modeled behavior and recommendations for the design of such tests are presented.
Quantitative Environmental Risk Analysis
Authors: Klovning Jorunn , Nilsen Espen Fyhn 
Published: December 2007

Abstract
According to regulations relating to implementation and use of risk analysis in the petroleum activities issued by the Norwegian Petroleum Directorate, it is mandatory for an operator on the Norwegian Continental Shelf to establish acceptance criteria for environmental risk in the activities and carry out environmental risk analysis.
This paper presents a ‘new’ method for environmental risk analysis developed by the company. The objective has been to assist the company to meet rules and regulations and to assess and describe the environmental risk in a systematic manner. In the environmental risk analysis the most sensitive biological resource in the affected area is used to assess the environmental damage. The analytical method is based on the methodology for quantitative risk analysis related to loss of life. In addition it incorporates the effect of seasonal fluctuations in the environmental risk evaluations.
The paper is describing the function of the main analytical sequences, exemplified through an analysis of environmental risk related to exploration drilling in an environmental sensitive area on the Norwegian Continental Shelf.
Integrated Horizontal Technology Recovers Attic Gas in West Delta 54 Field
Authors: Schroeder Tom , Mathis D. E. , Doyle B. J. , Wonish Bob 
Published: December 2007

Abstract
In 1994, PANACO, Inc. drilled two horizontal wells in the DP sand of West Delta 54 field - the No. 15 well and the No. 28. The DP gas reservoir had been discovered in 1956 at 3800' TVD, and its vertical wells had already produced 67% of its 28.3 BCF of recoverable gas. The new horizontal wells, designed to maximize recovery, have now produced at a combined rate as high as 25 MMCFPD. The scope of this paper is twofold: Evaluation of return permeability as influenced by a biopolymer mud system, which was used to drill the horizontal sections, andComparison of productivity from two horizontal wellbores of different lengths within the reservoir.
Analysis is based upon initial well tests in addition to the first six-month production history.
This case history may provide guidelines for development of other shallow, high porosity and permeability gas sand reservoirs.
Improved Fractured Reservoir Characterization Using Neural Networks, Geomechanics and 3-D Seismic
Authors: Zellou A. M. , Ouenes A. , Banik A. K. 
Published: December 2007

Abstract
In this paper, a new approach which uses seismic attributes in a quantitative manner to enhance the characterization of fractured reservoirs is presented. The new approach uses the seismic travel time to identify the reservoir structure and the thickness of the fractured producing formation. Using these data, a quantitative geomechanical model is constructed. When comparing the geomechanical models derived from seismic data and mapping methods, it becomes apparent that many structure details may be misrepresented and/or missed when interpolation methods are used for defining reservoir structure. Using a Neural Network and the available well data, the geomechanical model is correlated with the oil production. This model is compared to the seismic amplitude which appears to provide the best indication of fracture intensity in the case of the field studied. Given the seismic data, which are available over the entire reservoir, and the fracture model found by the neural network, the overall reservoir fracture network is predicted.
Splitting Pseudospectral Algorithm for Parallel Simulation of Naturally Fractured Reservoirs
Authors: Luan Zhi-an 
Published: December 2007

Abstract
Improved difference schemes are illustrated for Buckley-Leverret equation. Based on the schemes, new splitting pseudospectral algorithms for some parallel simulations of naturally fractured reservoirs are developed. The component-by-component splitting method effectively splits more complicated multidimensional (or multi-phase,multi-component) problems into simpler one dimensional problems which can be handled by the pseudospectral method or any highly vectorized technique of tridiagonal systems.These algorithms specially suit to accuracy, speed and memory requirements of simulations on a large scale.
Simultaneous Water and Gas Injection Pilot at the Kuparuk River Field, Reservoir Impact
Authors: Ma T. D. , Rugen J. A. , Stoisits R. F. , Youngren G. K. 
Published: December 2007

Abstract
Immiscible water-alternating-gas injection has effectively managed produced gas at the Kuparuk River Field, increasing field oil rate and recovery. Although I WAG economics are very favorable, a pilot study was undertaken to ascertain whether the separate gas injection system can be eliminated by simultaneously injecting water and gas in waterflood lines.
Static mixers were found to be necessary to disperse gas in a multiphase mixture flowing through a network of pipes. However, scale-up criteria for gas dispersing static mixers in multiphase pipe networks require additional refinement.
Reservoir simulation done to support the pilot project showed that simultaneous water-and-gas injection should provide better control of gas mobility than IWAG. This resulted in increased oil recovery and more steady gas production. During the typical IWAG process, the magnitude and the cyclic nature of GOR responses have caused problems for gas handling at the field facilities.
During the pilot, loss of injection rate was observed as the gas fraction in the injection mixture increased and the surface injection pressure was kept stable at about 2800 psi. Examination of Well 2D-16 data suggests that the observed rate loss was more likely due to the lower bottom-hole pressures than the relative permeability effects expected of two-phase flow in porous media.
Cavity Completion For Coalbed Methane Stimulation - An Integrated Investigation And Trial In The Bowen Basin, Queensland
Authors: Wold M. B. , Davidson S. C. , Wu B. , Choi S. K. , Koenig R. A. 
Published: December 2007

Abstract
Cavity completion stimulations have been trialled at two adjacent sites in the Bowen Basin, Queensland, Australia. The trials were conducted under thoroughly characterised reservoir conditions and were comprehensively monitored using multiple observation wells. Integrated with the trials were laboratory investigations of the fundamental mechanisms of cavitation in similar coals. These studies primarily comprised cavitation of coal blocks under full scale stress and pore pressure conditions, and numerical modeling of both the field and laboratory processes using both continuum and discontinuum models. Stimulation mechanisms are discussed in terms of two-phase flow, coupled mechanical - fluid flow in fractures, and coal failure under dynamic conditions.
Injectivity and Gravity Override in Surfactant-Alternating-Gas Foam Processes
Authors: Rossen W. R. , Kibodeaux K. R. , Shi J. -X. , Zeilinger S. C. , Lim M. T. 
Published: December 2007

Abstract
Surfactant-alternating-gas (SAG) foam processes can in principle combine high gas injectivity with low mobility at the front of the foam bank. Such a process can give the appearance of extremely shear-thinning behavior, in that the pressure gradient is remarkably low near the well. However, this appearance is due to the effects of declining water saturation near the well, not to the effects of high near-well flow rates on foam mobility. Preliminary simulation results suggest that as long as mobility is low in a region away from the well, high gas mobility near the well need not lead to gravity override. Indeed, since increased injectivity allows higher injection rates and thereby increased flow rates and pressure gradients away from the well, increased mobility near the well may help to reduce the risk of gravity override.
Experimental Evidence for Improved Condensate Mobility at Near-wellbore Flow Conditions
Authors: Boom W. , Wit K. , Schulte A. M. , Oedai S. , Zeelenberg J. P. W. , Maas J. G. 
Published: December 2007

ABSTRACT
The inflow performance of gas wells in gas/condensate fields may be impaired when condensate banks form near the wellbore as a result of the pressure dropping below the dewpoint. This impairment may be alleviated to some extent, however, by the increase in condensate mobility at the prevailing conditions, which are characterised by high gas flow rates and relatively low interracial tension. Scouting reservoir simulations indeed identified this mobility improvement to be a key uncertainty in well-deliverability forecasting for gas/condensate reservoirs.
Model experiments with core material from various gas/condensate reservoirs in Europe and the Middle East were therefore conducted at ambient conditions to assess the degree to which the mobility of condensate could be improved by the applied flow conditions. A wide range of relative permeability and of saturation were probed, and several orders of magnitude of capillary number, interfacial tension and absolute permeability were covered. In all cases, the results reveal a truly significant mobility increase. Moreover, it was experimentally demonstrated that the key parameter controlling this effect is the capillary number and not the interfacial tension alone. The dynamic relative permeabilities that were obtained from our experiments are currently being used for history-matching well tests with equation-of-state reservoir simulations.
Reservoir Performance History Matching Using Rate/Cumulative Type-Curves
Authors: Callard J. G. , Schenewerk P. A. 
Published: December 2007

Abstract
This paper presents an analysis technique for characterizing reservoirs from production performance. Unique to this technique is the incorporation of the instantaneous bottom-hole flowing pressure (BHFP) to both the production rate and to the cumulative production for a well depleting a reservoir. This allows a single rate/cumulative analysis for wells producing with constant BHFP, constant rate, and wells with variable rate or variable BHFP (including wells with shutins). This solution provides a powerful diagnostic type-curve which can be generated with almost any wellbore/reservoir situation encountered. Extension of the method to gas reservoirs through use of pseudopressure and viscosity-compressibility normalization allows these wells to be analyzed using the slightly-compressible fluid solution. Well performance during transient flow and depletion flow are examined. Simulation results are compared with the analytic solution. The use of spreadsheets to perform well test analysis is also demonstrated.
Numerical Simulation of Waterflooding in a Pancake Oil Column
Authors: Evans David E. 
Published: December 2007

Abstract
The H-21 Reservoir in the North Alazan Field is a South Texas, Frio Sand reservoir. It has a thin oil column, overlain by a large gas cap and underlain by water. Applicability of conventional waterflood prediction techniques was questionable as the prediction techniques was questionable as the pancake nature of the oil column could result pancake nature of the oil column could result in losing oil to the gas cap when waterflooding. A waterflood study utilizing a two dimensional, three phase, numerical, reservoir simulator was undertaken to evaluate the waterflood potential. Results simulating reservoir behavior in a cross-sectional model with several water injection patterns and injection rates showed that none of the schemes would substantially increase oil recovery in the reservoir due to uncontrollable migration of oil into the gas cap.

Introduction
The North Alazan Field is located in the northeast part of Kleberg County, Texas, as shown by Figure 1. The H-21 Reservoir was discovered in December, 1958, by Humble's King Ranch Alazan No. 6 and by February, 1963, the reservoir was developed with 49 completions to 80 acre spacing. Studies of reservoir performance indicated a gas-cap-expansion primary drive mechanism, aided by a pressure-maintenance, gas injection program and hindered by severe gas coning. Ultimate recovery was projected to be 22 percent of original oil in place. A study was begun to evaluate the waterflood potential of the reservoir as a means of potential of the reservoir as a means of increasing ultimate recovery. The pancake nature of the reservoir (the H-21 Reservoir has a thin oil column, overlain by gas and underlain by water) required the use of a reservoir model employing numerical simulation to select the waterflood scheme with the most potential.
This paper discusses how the numerical simulator was used to model the reservoir under waterflood and discusses the results of six waterflood schemes which were evaluated.
Occurrence of Cemented Reservoir Roof Rock And Geopressure Caprock and its Implication in Petroleum Geology and Geohydrology
Authors: Fertl W.H. , Timko D.J. 
Published: December 2007

Abstract
Diagenesis comprises processes of transformation through which, as a function of pressure, temperature and depth, compact rocks are formed from unconsolidated sediments. Interspace in such consolidating sediments generally is filled with aqueous solutions, by far exceeding in quantity local accumulations of oil and gas. These interstitial solutions, their composition, movement, and mixing are important factors in diagenetic processes. The latter alter sandstones and clay minerals, both equally important in petroleum geology and geohydrology.
Of great significance is the occurrence of cemented layers which can readily be located and correlated by means of conventional well logs. Such cemented barriers occur as roof rocks, especially in structurally high positions in both oil or water bearing reservoir rocks, and as caprock sealing geopressured zones. Distribution of these cementing materials can be related to hydrodynamic conditions, planning of completions and the presence of abnormal pressure conditions. pressure conditions.

General Discussion
Compaction of argillaceous sediments causes movement of large amounts of aqueous solutions through the subsiding sedimentary column. While moving through sandstones and shales, the composition of these solutions may have changed many times considering the geologic time factor involved. Furthermore, any movement of formation waters across a sand/shale boundary will result in changes in the brine concentration in the sandstone. This is caused by the "salt filtering" effect of various clay minerals in respect to electrolytic solutions.
As early as 1933, it was suggested by Schlumberger et al that clays and shales act as semipermeable membranes and in 1947 the salt filtering properties of clays were shown experimentally by Buneev et al. A recent and excellent review of the relative factors influencing membrane filtration effects in geologic environments has been given by Berry 1969.