bluuebunny/crossref_metadata_2025_split huggingface dataset:
Liquid Addition to Steam for Enhancing Recovery (LASER) of Bitumen with CSS: Evolution of Technology from Research Concept to a Field Pilot at Cold Lake
Authors: Léauté Roland P. 
Published: December 2007

Abstract
This paper describes the process of injecting a liquid (C5+) hydrocarbon as a steam additive in a CSS mode of operations. The process has been termed LASER, for "Liquid Addition to Steam for Enhancing Recovery".
The process concept was first tested in a 3D physical model apparatus using Cold Lake bitumen. A sustained uplift in bitumen production was observed in later CSS cycles when compared to other tests conducted without liquid addition. Based on numerical simulations, these effects can be attributed to additional viscosity reduction of heated bitumen when contacted with solvent. For bitumen-diluent mixtures, Shuh’s method of viscosity prediction of bitumen with liquid hydrocarbons is adequate to make realistic viscosity predictions based on actual measurements. Field-scale simulations were used to support LASER performance trends from the physical model and establish the optimal timing for applying the technology in the field.
The key recovery performance indicators for LASER technology are (1) bitumen uplift over continued CSS performance and (2) fractional recovery of the injected diluent. A field pilot has been designed based on expectations of (1) an improvement of 33% in the cycle Oil-Steam Ratio (OSR) and (2) diluent recovery of 66% using 6% v/v of diluent injection with steam. The pilot location was chosen based on various factors, including improved characterization of historical performance within and around the pilot location. This was achieved by developing a novel multivariate analysis technique to correlate current OSR field performance and reduce associated background noise.
An extensive monitoring program has been developed for the pilot. This program is critical for developing a reliable characterization of the diluent recovery. Diluent injection began in April 2002, and the pilot is expected to last approximately 2 years, corresponding to the average length of CSS cycle 7 at Cold Lake.
Injection Pressures for Geomechanical Enhancement of Recovery Processes in the Athabasca Oil Sands
Authors: Collins Patrick M. 
Published: December 2007

Abstract
This paper describes a geomechanical approach to the determination of injection pressures that will result in formation shearing within the Athabasca oil sands. The enhancement of in situ permeabilities, resulting from shearing, is a beneficial phenomenon and often an essential prerequisite of many successful in situ recovery processes.
This geomechanical analysis is based upon the general geological setting in the Athabasca oil sands, observations made from field data, published laboratory data, and geomechanical principles. The first objective was to estimate the existing stress state in the rock. This determination was based on elastic theory and tectonics, and fitted to field measurements of the minimum in situ stress from minifrac tests in the Athabasca oil sands. The methodology also calculates the maximum horizontal stress, a parameter that is extremely difficult to measure, yet is an important parameter for most stress analyses. The resultant stress anisotropy creates the potential for formation shearing; a potential that is unleashed once the effective stresses are sufficiently reduced with high injection pressures.
Lastly, the amounts by which injection pressures must be increased for shear failure are provided, assuming typical values of formation strength.
The analysis begins with a determination of the minimum in situ stress, as a function of depth. This is the fracture closure pressure that is a useful parameter in determining fracture treatment pressures, fracture containment, and fracture orientation. The associated tectonic strain is used to calculate the maximum horizontal stress. Using the maximum and minimum stresses, the injection pressure at which extensive shearing will occur is calculated. This is the geomechanical optimum operating pressure. While other considerations may favour a lower operating pressure, recovery processes that rely upon high in situ permeabilities may not be viable at lower injection pressures.
The methodology presented is applicable to other regions.
Fracture Evaluation With Pressure Transient Testing In Low-Permeability Gas Reservoirs. Part I: Theoretical Background
Authors: Lee W.J. , Holditch S.A. 
Published: December 2007

Introduction
The purpose of this paper is to summarize the theoretical background of methods which we have attempted to use to determine formation permeability, fracture length, and fracture conductivity in low-permeability, hydraulically fractured gas reservoirs. This summary is intended to emphasize the major strengths and weaknesses of the methods studied. These characteristics have not always been emphasized in the original literature and have, in some cases, remained obscure to the practicing engineer. This pape is a companion paper to SPE 79301, in which our experience in application of these techniques to problems arising in practice is discussed. Test analysis methods discussed in the paper include (1) a method applicable only after a 'pseudo-radial' flow pattern is developed in the reservoir, (2) a method applicable when linear flow dominates in the reservoir, (3) published type curves, with emphasis on those which include finite-conductivity fractures, (4) a modification of linear-flow techniques useful for finite-conductivity fractures, and (5) use of finite-difference reservoir simulators in a history-matching mode.

Pseudo-Radial Flow
Russell and Truitt2 pioneered application of methods based on the assumption of 'pseudo-radial flow' in a fractured reservoir for determination of formation permeability and fracture length. A working definition of pseudo-radial flow is that sufficient time has elapsed in a buildup or drawdown test so that bottom-hole pressure varies linearly with flow time (drawdown) or the Horner time group, (tp+Î"t)/Î"t (buildup), as expected for radial flow in an unfractured reservoir.
In an infinite-acting (unbounded) reservoir, the analysis technique is based on the use of skin factor, s, which can be calculated fromEquation 1*
and the observation tat, for infinitely-conductive vertical fractures,Equation 2
Eqs. (1) and (2) can be combined to avoid the need for the intermediate step of calculating skin factor, s,Equation 3
In principle, we can plot buildup test data on a conventional Horner graph, determine the slope, m, and thus estimate formation permeability (k=162.6 qgBgiÎ¼i/mh) and determine fracture half-length, Lf, from Eq. (3). (See Figure 1.) In practice, there are three serious problems with this method:The time required to reach the required straight line where the slope is related to formation permeability can be impractically long (months or years) in low permeability gas reservoirs with long fractures, as demonstrated by Gringarten, et al.4 and Cinco5 et al.;Implicit in the method is the assumption of infinite fracture conductivity, which is not always valid6; and,By the time the pressure transient has moved beyond the region of the reservoir influenced by the fracture, effects of the reservoir boundary may have already become important, preventing development of the proper slope, m.
Geological Characteristics And Engineering Capabilities Of Wells 31-13 And 498-4-1
Authors: Timmerman E.H. , Collins T. , Ishteiwy A.A. , Chancellor R.E. 
Published: December 2007

Abstract
Two wells in the Northern Piceance Basin were variably stimulated in correlative Mesaverde rocks. The well which encountered the rock sequence at greater depth in the presence of more intensive natural fracturing had better productive characteristics and better before and productive characteristics and better before and after flow capacity. Geology, flow data and buildup data are in agreement. The data also indicate that the overall net benefit of massive fracture is about the same as obtainable from a moderate size fracture job. Methods used to analyze the buildup tests are illustrated in the Appendix section.
Selective fracturing of available individual gas zones using moderate sized operations per zone is useful. Hopefully, a technique can be developed which, in the field, will attain benefits indicated by theory to be obtainable from massive fractures in Western Tight Gas pays. Frac fluids can be displaced today, but results are less than desired.

Introduction
Two industry-government projects to improve production from tight gas sands of the Mesaverde production from tight gas sands of the Mesaverde Formation, Northern Piceance Basin, have progressed sufficiently to yield data which progressed sufficiently to yield data which (supplemented by earlier but less thoroughly documented drilling and completion efforts in the general area) is of correlative interest. A total of nine fracture stimulation treatments have been performed in the two wells shown on Figure 1. Well No. 498-4-1 (498) is about 11 miles southwest of Well No. F31-13G (31-13). Structurally, Well No.498 is approximately 3,000 feet higher than Well No. 31-13. Well No. 498 is located on regional (41) while Well No. 31-13 is near the crest of the Piceance Creek Dome. The Dome experienced strong structural movements following deposition of Mesaverde sediments.
P. 271
Modeling Sand Production and Erosion Growth under Combined Axial and Radial Flow
Authors: Wan Richard G. , Wang Jin 
Published: December 2007

Abstract
The paper investigates the phenomenon of sand production in both axial and radial flow conditions using a coupled particle erosion-fluid transport-stress model that has been developed recently by the authors. We first examine sand production and wormhole growth in a sand pack as heavy oil is being drawn from it through a small orifice. Numerical results are in close agreement with experimental data available for the sand pack experiment. In particular, the computed porosity field and its temporal evolution during wormhole propagation match very well with available CT scan images of the sand pack. Then, we model a sand production hollow cylinder test in which sand is being produced under combined axial and radial flow of light oil in a sandstone specimen. Aspects such as sand flux and porosity evolutions, as well as erosion growth around the inner wall of the cylinder are investigated using the numerical model.
Scale Inhibition Problems Associated With North Sea Oil Production
Authors: Boyle M.J. , Mitchell R.W. 
Published: December 2007

Abstract
Suitable chemical treatment of North Sea oil and gas production plays a small but vital role in determining the production plays a small but vital role in determining the success of the project. During the initial period of production from a new oilfield, the chemical treatment requirements are generally minimal. This situation changes dramatically as the field life progresses and water production commences. At that time a variety of chemicals will probably be required including demulsifiers, corrosion inhibitors. effluent treatment compounds and scale inhibitors. Whilst for many of these products there are well defined test methods and selection techniques available, this is a particular problem with scale inhibitors. In the majority of particular problem with scale inhibitors. In the majority of cases it is very difficult to simulate the scaling situation present in the field by laboratory methods. present in the field by laboratory methods. The paper reviews some scale inhibitor selection techniques used in the past and describes a novel simulation test to monitor inhibition and flow pattern influence around an injection or production well bore. This method has been used to rank the efficiency of commercially available scale inhibitors for both the Forties injection and production systems and will be discussed in terms of the practical problems involved. problems involved

Introduction
Problems arising from the production of scale are commonplace in oilfields. The precipitation mechanism is often complex and may be due to a variety of effects including changes in system conditions (e.g. pH, pressure. temperature etc.), reservoir conditions or incompatibility between injected water and formation water. The present paper discusses carbonate and sulphate scale formation in the Forties Field and some of the laboratory inhibitor selection techniques used in the selection of suitable scale inhibitors for field use both in the Forties injection and production systems. In particular a novel test method is described which is being used in the laboratory to monitor inhibitor and flow pattern influence on formation scaling.
Field Studies: A Progress Report On The Contribution Of Logging
Authors: Boutemy Y. , Clavier C. , Simond R.F. 
Published: December 2007

Introduction
In recent years a new method has evolved which allows the merging of wireline surveys, core and other sample data, and geological and geophysical information to estimate reservoir properties. The method makes extensive use of 'Kriging' and multidimensional histograms. The name 'Field Study' has been retained to depict very generally the method. A field study consists, therefore, of a unified interpretation of wireline measurements, core and sample data, done on a fieldwide basis. This fundamental work is followed by an estimation of the spatial distribution of various key parameters over selected reservoirs of a field. Reservoir geometry, thickness, distribution of porosity, permeability and fluid saturation are typical parameters to permeability and fluid saturation are typical parameters to be estimated together with their integration and required combinations to obtain total pore volume, hydrocarbon in place, permeability-height, etc. All these factors are place, permeability-height, etc. All these factors are crucial to the economics of field development and productivity. productivity. At present, a large part of the input parameters for such a study consists of open-hole wireline measurements and/or data subsequently obtained from these by computer processing. processing.
"Real Gas Pseudo-Time" - A New Function For Pressure Buildup Analysis Of MHF Gas Wells
Authors: Agarwal Ram G. 
Published: December 2007

Abstract
A new time function has been defined which considers variations of gas viscosity and compressibility as a function of pressure, which in turn is a function of time. This function appears to be similar to the real gas pseudo-pressure, m(p) of Al-Hussainy et al., which takes into account the variations of gas viscosity and z-factor as a function of pressure. However, this is an approximate function as opposed to m(p). This time function will be referred to in this paper as the real gas pseudo-time, t a(p). This function has aided in pseudo-time, t a(p). This function has aided in post-treatment-pressure buildup analysis of post-treatment-pressure buildup analysis of fractured (including MHF) gas wells by type curve analysis. Results of computer simulated pressure buildup analysis indicate that the use of t a(p) provides satisfactory values of computed fracture provides satisfactory values of computed fracture lengths in fractured gas wells.
In this paper the real gas pseudo-time is described and its application is demonstrated by means of example problems. Although the discussion in this paper is limited to pressure buildup analysis of vertically fractured gas wells, the utility of this function is not meant to be restricted to such wells only.

Introduction
In recent years, type curve analysis methods' have become well known in the petroleum industry for analyzing both pressure drawdown and buildup data in oil and gas wells. These methods are meant to be used in conjunction with the conventional methods whenever possible. Exceptions appear to be MHF gas wells with finite flow capacity fractures where conventional methods are not readily applicable and, at least to date, only type curve methods appear practical to determine fracture length and fracture flow practical to determine fracture length and fracture flow capacity. Although the majority of published type curves, including those for MHF wells, are based on the pressure drawdown solutions for liquid systems, they can be used in an approximate fashion to analyze pressure data from real gas wells. The first requirement is that the dimensionless pressure and time variables are appropriately defined for gas wells. For example, to use the liquid system type curves for an MET gas well, dimensionless variables are defined as follows:
Dimensionless pressure,
(1)
(In SI units, the numerical constant is 128 × 10(-3))
Dimensionless pressure, for a gas well, may also be expressed in terms of Delta (p) or Delta p.
Dimensionless time,
(2)
(In SI units, the numerical constant is 3.6 × 10(-9))
The definition of dimensionless fracture capacity remains the same.
(3)
Note that in Eq. (1), the real gas pseudo-pressure, m(p) of Al-Hussainy et al. has been used to take into account the variations of gas viscosity and z-factor as a function of pressure. In Eq. (2), viscosity-compressibility (mu c t)i is shown to be evaluated at the initial reservoir pressure. pressure.
An Improved Nuclear Magnetism Logging System And Its Application To Formation Evaluation
Authors: Herrick R.C. , Couturie S.H. , Best D.L. 
Published: December 2007

Abstract
A new version of the Nuclear Magnetism Logging tool (NML) has been developed and will be available for limited commercial use in the near future. The tool measures the earth's field proton free induction decay of formation fluids. Since this tool operates exclusively with the CSU well-site computer system, it is capable of real-time computation and presentation of the free fluid index (FFI) and the spin-lattice relaxation time (T1). Other new features include a centralized coil sonde and improved electronics for higher signal-to-noise ratio and greater reliability. Engineering prototypes have been extensively field tested and have proven to be dependable in a logging environment. Logs correlate well with other porosity measurements from core data and sonic, nuclear, and electromagnetic propagation well logging tools. Data from NML logs can be applied to the determination of irreducible water saturation, porosity in unusual lithologies, residual oil saturation, and porosity in unusual lithologies, residual oil saturation, and to the estimation of permeability.
Safety Economics and Rig Contracts
Authors: Osmundsen Petter , Toft Anders , Dragvik Kjell Agnar , Heldal Tor , Larsen Inge Arild 
Published: December 2007

Abstract
The main topic of this article is how financial incentives can impact focus on safety. The case used is the relationship between the operator of a petroleum license and a drilling contractor. Focus is placed on how an operator can influence the actions of a drilling contractor with the aid of financial incentives both in connection with hiring in rigs and contract design. Furthermore, the article examines how these incentives can influence the contractor's focus on safety.
The report is based in part on contract and incentive theory – see e.g. Laffont and Tirole (1989) and Salanié (1999) – and in part on empirical data. The empirical basis consists of various drilling contracts utilized on the Norwegian and British shelves, as well as meetings and informal conversations with representatives of oil companies, rig companies and safety administrators.
There are some general development trends in the offshore sector; such as outsourcing, focus on financial indicators and increased focus on incentive-based compensation schemes, that have led to an increased emphasis on incentive clauses in contracts, thus making this topic even more relevant. The growing degree of outsourcing has meant that transactions previously conducted within the same organization are now governed by means of contracts between independent companies. We also see an increasing degree of management by objectives in the companies, including increased emphasis on financial indicators. One of the effects of this change appears to be a growing emphasis on financial performance on a quarterly and annual basis. This management by objectives is followed up internally within the companies and in contracts between independent companies, in part through the formulation of incentive agreements.
Treatment of Waste Water: A Reed Bed-Environmental Case History
Authors: Guirguis Maurice 
Published: December 2007

Abstract
A reed bed or constructed wetland has proven to be an effective, sustainable, reliable, and economical treatment method for sewage or industrial waste. The reed-bed treatment systems in desert area 103, Libya, are self-contained, artificially engineered wetland ecosystems. They are designed to optimize the microbiological, chemical, and physical processes naturally occurring in the wetland. This paper describes the construction of the treatment plant, its wastewater treatment capacity, and the positive impact it has had on the environment and the local community.
The reed-bed wastewater treatment plant in desert area 103 is the first wastewater treatment facility in the Libyan desert oil fields. It can treat up to 350 m3 of wastewater effluent per day using automatic submersible pumps. The reed bed is lined with plastic sheets underneath the gravel to prevent effluent from seeping underground. Wastewater is discharged to the reed bed for treatment after primary tank screening and settling. Wastewater enters the reed bed by gravity via clean stone for biological treatment on the stone surface.
The common reed Phragmites australis is indigenous to the Libyan desert 103 area. It has the ability to transfer atmospheric oxygen from its leaves down through its stem, porous septa, and rhizomes, and out into the rhizosphere (root system). As a result, a very high population of microorganisms exists in the rhizosphere, in zones of aerobic, anoxic, and anaerobic conditions.
The plant is currently treating between 60 and 80 m3 of wastewater per day. The reed-bed wastewater treatment project improved the scenery and odor of the wastewater area, protected the potable water well in the middle of the camp and the water table, and reduced the ecological impact on the endangered wildlife in the area. This project has shown that treating wastewater in remote locations is feasible.