bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ranking Geostatistical Models Using Tracer Production Data
Authors: Saad Naji , Maroongroge Vichai , Kalkomey C.T. 
Published: December 2007

Abstract
The stochastic modeling approach can result in a large number of realizations that must be ranked so that fewer numbers can be used in more detailed flow simulation to quantify the uncertainties in reservoir performance. The objective of this paper is to investigate the use of tracer production data for the purpose of ranking geostatistical realizations. Here we introduce ranking of geostatistical models based on the first moment of the tracer production data. In this study we have used single-phase tracer simulation to rank a large number of detailed geostatistical realizations. The results of the ranking based on single-phase tracer simulations are compared with rankings based on increasingly more accurate two-phase flow simulations of a waterflood recovery process. In addition to the analysis of the integrated tracer breakthrough curve for ranking, a new tracer test used for estimating reservoir heterogeneities, called Vertical Tracer Profiling (VTP), is used to rank the generated geostatistical models. This interwell tracer test is performed by injecting and/or collecting tracer samples at different locations along the wellbore Using the more detailed VTP ranking, we investigated the differences between the tracer ranking and waterflood simulation ranking.
The results indicate that there is no correlation between the ranking based on tracer breakthrough time or peak tracer concentration and ranking based on cumulative oil recovery. Ranking based on the tracer's mean swept pore volume, first moment of the tracer production data, shows the highest degree of correlation with ranking based on cumulative oil recovery from waterflood simulations.
Improved Technique for Off-Center Well Modelling in Multidimensional Reservoir Simulation
Authors: Agaev G.S. 
Published: December 2007

Abstract
At present one of effective tools of real reservoir systems simulation is the numerical solution of partial differential equations of multidimensional multiphase filtration theory with combination of well equations. Because of that the wells are a single source of information about reservoir systems, the realistic description of fluid flow around the wells is one of most challenging aspects of reservoir simulation.
In conventional reservoir simulation there is accepted that the boundary conditions for reservoirs must be to given in the production (injection) wells and in the external (internal) boundaries. Wells are assumed to be in the gridblock centers without taking into account their exact position. It leads to neglecting of closest neighbouring cells influences and the fluid flow around an off-center wells is described incorrectly. This problem is especially important in the full-field simulators development when the reservoir systems approximate with very coarse gridblocks and reservoir produces (injected) by numerous off-center wells.
In this paper the new well representation technique in the reservoir simulation is described. This technique allows to give exact off-center well position and take into account the influence from closest neighbouring gridblocks. The application of this technique is described in the explicitly and implicitly formulations.
The results of calculations by using of suggested technique was matched with results of reservoir simulation by fine-grid application and showed a good agreement. In this paper there is illustrated that the implementation of this technique allows to improve the accuracy of results and considerable decrease of computing time because of that suggested technique assumes the use of coarse grids.
Development and Testing of a Multi-Lateral System
Authors: Longbottom J.R. 
Published: December 2007

Abstract
This paper will discuss the progress that has been made in the development of multi-lateral completions that have a broader scope of application than those originally used in hard rock formations. Numerous multi-lateral wells have been drilled, particularly in the Austin Chalk where openhole completions are common. In other lithologies, a more sophisticated completion method is required to maintain borehole stability, flow control/well maintenance capabilities. For this purpose, a project was undertaken to develop a multi-lateral system that
- mechanically connects the lateral liner to the parent casing,
- allows through tubing re-entry access to selected laterals, and
- seals the junction between the lateral and parent bore to enable flow control capability.
In addition, the hole size of the lateral has been maximized in comparison to the parent wellbore casing. Bench tests of the components of the system were performed, and then, a full scale system test was conducted. An integrated development approach with a multi-disciplinary design team and direct producing company involvement was used. The system developed to fulfill the criteria described above was successfully tested and is currently undergoing field installations.
A Practical Model for the Effect of Salinity on Gas Hydrate Formation
Authors: Edmonds B. , Moorwood R. A. S. , Szczepanski R. 
Published: December 2007

Abstract
This paper is based on a previously developed thermodynamic model for gas hydrates and hydrate inhibition. The model uses a cubic equation of state for the fluid phases and parameters have already been determined for the following inhibitors: methanol, MEG, DEG and TEG.
The paper describes the extension of the model to include the effect of salinity in produced water or sea water on hydrate formation. To ensure the model would be of practical value, it was designed with the following characteristics: it should be simple to use requiring as input no more than a typical ion analysis table from a laboratory report. It should be based on a cubic equation of state suitable for engineering calculations and the model should operate reliably at temperatures and pressures normally encountered in oil and gas production.
The model represents the ionic components in water by a single salt pseudocomponent of the equation of state. The physical properties of the pseudocomponent were set by regressing them to experimental data for sodium chloride solutions. Results will be presented to show that the model can simultaneously represent the lowering of the hydrate dissociation temperatures, the depression of the freezing point of water and the reduction in the water vapour pressure (osmotic coefficient).
As sodium chloride is usually the dominant component in produced water or sea water, other salts are handled on a sodium chloride equivalent basis, so that only one salt pseudocomponent is needed for practical calculations. Data for the effect of natural waters supports the use of this approximation.
In practice, a hydrate inhibitor may be added to the water phase so it is important that the inhibition model can give accurate predictions in the presence of saline solutions. This has been confirmed by investigating the salting-out effect for methanol and results are shown for salt-water-methanol mixtures.
Practical ways of accessing and applying the model are summarised. These include using the model as a standalone computer program, accessing the model via a spreadsheet or using the model as an object code library or as a dynamic link library.
Environmental Self Audits for Upstream Petroleum Operators
Authors: Garvey C. A. , Gray W. A. 
Published: December 2007

Abstract
This paper presents the topic of environmental auditing so that upstream petroleum operators may be able to conduct an internal environmental audit of the properties under their care. The paper also discusses the role of environmental auditing in environmental management to assess the effectiveness of management controls in achieving compliance and in protecting the environment. Planning and implementation of the environmental audit process is covered in sufficient detail for practical use. A pre audit selection matrix to identify properties most likely to need auditing is presented and discussed. A check list prepared specifically for petroleum resource properties is also included By following this methodology the audit will document the degree of environmental compliance and how to achieve improved environmental performance. References and regulations mentioned apply to Western Canada and in particular to the province of Alberta.
The causes of environmental degradation and their prevention or minimization is the focus of this paper.
Predicting the Long-term Recovery From Naturally Fractured Reservoirs Utilizing Production Test Data and a Conventional Reservoir Simulator
Authors: Grant J. R. 
Published: December 2007

Abstract
Recently Imperial Oil Limited has been pursuing gas plays in North-Eastern British Columbia where single wells have the potential to recover gas in the 30-300 Bcf range. The tie-in costs for these wells are very high due to acid gas content, mountainous terrain and long distances to tie-in points. A reliable prediction of the recoverable reserves helps determine if a tie-in is economic and manage the business over the long-term. The intent is to demonstrate how the long-term recovery from naturally fractured gas wells can be accurately evaluated with buildup tests and a conventional finite difference reservoir simulator.
The decision to tie in a well is strongly based upon its initial deliverability. However, this is not generally appropriate since the initial deliverability and the longterm recovery are controlled by different factors. The initial deliverability is a function of the fracture system around the wellbore while the long-term recovery is related to the fracture system's extent and the ability of the reservoir matrix to recharge the fracture system. Other evaluation techniques such as open hole logs and core can only evaluate the fracture system at the wellbore which again only relates to the initial deliverability. Properly planned and executed production tests, in conjunction with reservoir simulation, can provide accurate evaluations of long-term recovery potential. However, the current suite of dual permeability/porosity simulators are either too simplistic to be of any use or very complex and difficult to use. Considerable lime and money could be saved if a conventional finite difference reservoir simulator could be used.
Two example wells will first be presented to demonstrate how a conventional reservoir simulator can be used to model the long-term production from a naturally fractured reservoir. It will then be demonstrated how a properly conducted flow and buildup test used in conjunction with a conventional simulator can be used to predict the longterm deliverability.
A New Numerical Model for Two-Phase Flow in Liquid-Cut Gas Wells
Authors: Li Yingchuan , Du Zhimin 
Published: December 2007

Abstract
A new model is proposed for predicting the pressure drop in liquid-cut gas well tubing. The liquid holdup is modeled as a function of dimensionless gas and liquid velocity numbers, as well as liquid viscosity number. It involves five parameters that are related to flow regimes and can be optimized using the field data. The friction loss is based on Mukherjee and Brill correlation. In this model, the pressure gradient equation is treated as an initial value problem for an ordinary differential equation, and is directly solved by Runge-Kutta method.
Based on the field measured data from 159 gas wells covering a wide range of production conditions, the model was found to be able to predict the pressure drops with an improved overall accuracy compared to the modified single-phase model and five commonly used empirical correlations.
Sensitivity of the models to liquid/gas ratio is also presented.
Integrated Applications for Infield Reserve Growth in Midcontinent Gas Reservoirs, Boonsville Field, Fort Worth Basin, TX
Authors: Lancaster David E. , Hardage Bob A. , Carr David L. , Hamilton Douglas S. , Elphick Robert Y. , Fate Thomas H. 
Published: December 2007

Abstract
Reservoir compartments identified in the Boonsville (Bend Conglomerate Gas) field, Fort Worth Basin, TX occur as a result of subtle structural and stratigraphic controls. Structural compartmenting results from previously unrecognized low-displacement faulting associated with karst collapse in deeper carbonate rocks. Stratigraphic compartments may result from surface, facies, or diagenetic boundaries. Some sequences within the Bend Conglomerate were imaged quite well using 3-D seismic, while others proved difficult to distinguish, especially when those units were associated with subtle impedance contrast or were extremely thin. Multiple stacked completion opportunities will typically be needed for economic success in new wells as well spacing is reduced, but analysis of the 3-D data suggests that stacked trapping geometries commonly exist. In addition, the influence of the vertical karst collapse features on Bend Conglomerate stratigraphy also suggests the opportunity for finding multiple stacked, and at least partially isolated, reservoirs.
A New Method for Predicting the Law of Unsteady Flow Through Porous Medium on Gas Condensate Well
Authors: Yu Xiong , Lei Sun , Liangtian Sun , Shilun Li 
Published: December 2007

Abstract
In order to consider the influence of variation of retrograde condensate saturation on well performance during production process in low permeability condensate reservoirs, this paper presents a new method to describe two-phase unsteady flow in formation around condensate well by using phase equilibrium and theories of unsteady flow through porous medium. The method takes into account the effect of retrograde saturation caused by phase behavior change on gas phase permeability and a new productivity prediction method by combining the variation has been offered. The method can be used to predict the distribution law of condensate saturation, pressure and relative permeability along radius direction as well as dynamic IPR curve and dynamic skin created by liquid saturation near wellbore in different production period. The method can also be used to predict effect of the dynamic skin on production. The application indicates that the method can reasonably describe the dynamic extension of retrograde condensate radius, the resistance effect of liquid dropping out on gas flow, and more rationally predict saturation variation near wellbore

Introduction
When we compare the general gas reservoirs with gas condensate reservoirs, there are many special factors which affect performance of gas condensate reservoir in exploitation process. For instance, the prediction on performance of gas condensate well is related to the law of gas condensate flow through the porous medium. In formation, the liquid will drop out from gas with pressure decline. It greatly affect the flowing feature through exploitation process. The condensate oil saturation around wellbore will be greater than that in the place far away from the wellbore due to the effect of the pressure distribution, the oil absorbed by rock, capillary forces and flowing feature. All of these will affect gas flow characteristics and change the property of well inflow performance. In these cases, not only the volume of dropping out liquid but also the flowing feature of it will play a part. Therefore, the existence of condensate oil will affect the gas condensate mixture flow to borehole, and its effect varies with time. We can more rationally and economically exploitate the oil-gas resources if these phenomena can be adequately described.
O'Dell and Miller presented a simple method based on steady-state flow concepts that can be used to estimate quickly the deliverability from the well. Results obtained using this method indicate that prediction of producing well rates will be presimistic if the average reservoirs pressure is below the saturation pressure of the in place fluid.
D.D. Fussell described the use of modified version of one-dimensional radial model developed by Rocbuck etc. to study the long term single-well performance.
P. 665
Application of Pulsed Neutron Logs for Through-Casing Evaluation of Gas, Oil, and Lithology
Authors: Jacobson L.A. , Wyatt D.F. 
Published: December 2007

Abstract
Modern pulsed neutron capture (PNC) and pulsed neutron spectrometry (PNS) tools provide new information about lithology that can be important in gas and oil reservoir evaluation. New PNC tools, besides the usual capture cross section measurement, also provide useful lithology information and can pass through-tubing. The PNS tools provide highly accurate complex lithology information in addition to the primary oil saturation (carbon-oxygen) measurement. Discrimination between tight limestone and gas-saturated sandstone is enhanced through application of either of these two logging tools.
The newest PNC tools also provide several neutron count-rate ratios sensitive to formation gas. A near-far capture ratio, a near-far inelastic ratio, and an inelastic-to-capture ratio provide an array of measurements that have slightly different responses to gas usually allowing for definitive identification of gas saturated reservoirs. Production problems in reservoirs caused by water movement in the casing or cement annulus between zones can often be detected by oxygen activation logging using either tool. Furthermore, flow can often be determined as inside or outside the casing.
Field examples illustrate the benefits of using pulsed neutron logging tools for oil or water saturation determination and lithology evaluation in mixed limestone/dolomite carbonates. Additional field examples will demonstrate techniques for gas detection using the numerous PNC measurements. Finally, log examples will illustrate the use of oxygen activation for detecting undesirable water flow both inside and outside the casing.

Introduction
An early PNC service introduced in 1982 (TMD*) provided a formation capture cross section measurement (FM), the near/far countrate ratio (RTMD) which is sensitive to porosity. and the total near and far detector countrates (NTMD and FMD) which when used together provide a gas indication. Modifications to the original TMD tools have added the total inelastic countrate from the far detector which provides another measurement with gas sensitivity. In 1994 Halliburton introduced the TMD-L,* which provided all the earlier measures plus spectral measurements obtained from the far-spaced detector. In a 1-11/16" (43 mm) diameter tool the detectors are necessarily small, so the total count in the spectrum above 1 MeV is low. Usable results require slow logging speeds and/or merging multiple passes to improve the statistical precision of the answers. Where spectral information is needed, slowing down from the standard logging speed of 20 ft/min. (6.1m/min.) to 10 ft/min. (3.1 m/min.) is required. Best results are obtained if three passes recorded at 10 ft/min. (3.1 m/min.) are merged. These spectral measurements can be used for lithologic identification. Spectral measurements obtained during the background measurement period provide a determination of the oxygen activation. This is a useful measure of upward water flow during normal logging operations.
P. 685
Development Drilling in a Gas-Affected Reservoir: Kuparuk River Unit, Drill Site 1B
Authors: Foster G.W. , Pearson C.M. , Moothart S.R. 
Published: December 2007

SPE Members

Abstract
Oil production in the early 1990's from Drill Site 1B (DS-1B) in the Kuparuk River Unit was languishing. To the east, lean gas injection in a gas storage area was migrating onto the drill site. The waterflood portion of the drill site was rapidly maturing, while high gas oil ratio (GOR) wells in the gas affected portion of the drill site could only be operated for relatively short periods of time due to gas handling facility limitations.
A thorough review of the geology and production history, in conjunction with recently available 3-D seismic information, revealed a more accurate method of predicting sand thickness and net pay trends. The sand trends were mapped using this new method, which aided in the placement of a water injection well which was used to mitigate gas encroachment from the gas storage area.
Producing GOR's in previously gas affected wells fell rapidly following water injection in the new well. Halting the gas migration allowed for the drilling of seven additional wells resulting in increased incremental oil production.

Introduction
Located in the Alaskan arctic, the Kuparuk River Field is one of the United State's largest producing oil fields (280,000 barrels oil per day), and covers an area of approximately 115,000 acres. The field was discovered in 1969, but was not deemed economic for development until 1977, after completion of the Trans Alaska Pipeline. Figure 1 shows the field location on the North Slope of Alaska. Field development was started using gravel pads as central drill sites from which deviated wells are drilled to drain a four section area (4 square miles). Initial development is on 160 acre well spacing with some 80 acre infill locations.
The Kuparuk reservoir is a sandstone at approximately 6000 feet subsea with solution gas drive as the primary production mechanism. The majority of the field is under secondary recovery receiving pressure support through a combination of waterflood and water alternating immiscible and miscible gas injection. Previous reports have documented both the geological description and the reservoir mechanisms of the field.
Production occurs from two horizons within the Kuparuk sandstone. An upper sandstone interval, referred to as the C Sand, is present over most of the southem half of the field and consists of very coarse to very fine grained siderite and sandstone. With average permeabilities of 130 md to 2600 md, and net pay ranges up to 80 ft, the C Sand typically produces at rates from 1000 to 5000 barrels per day (BPD).
The A Sand, the lower producing zone, is present throughout the field and contains 65% of recoverable oil in place. Six distinct subzones exist throughout the field with as many as three of these intervals present in a single well.