bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effects of Proppant Selection Upon Well Productivity—A Review of Over 650 Treatments in the Cardium Formation
Authors: Rightmire C. M. , Leshchyshyn T. T. , Vincent M. C. 
Published: December 2007

Abstract
Effects of proppant selection on well productivity are demonstrated in a large case study covering 2,300 square miles [6,000 square kilometers] in Alberta, Canada. In 80% of cases studied, wells fractured with ceramic proppant provided significantly higher gas production rates compared to wells propped with sand or other materials. The most frequently stimulated formation in the Western Canadian Sedimentary Basin (WCSB) is the Cardium formation of the Late Cretaceous period. Records indicate that across the basin the Cardium formation has received over 12,500 fracture stimulations during the last 50 years.
This study includes a review of 1,600 wells operated by 96 companies. On average, 156 new wells have been drilled annually since 2000. Record numbers of new wells were completed in 2004, and the number of Cardium wells completed in the last four years exceeds the total from the preceding two decades. A detailed database containing available fracture treatment and production data was compiled from government records and service industry sources. This paper summarizes a study of over 750 well stimulations.
Various stimulation strategies have been employed in the Cardium development. This paper examines productivity of hydraulic fractures propped with various materials and placed with a variety of fluid systems. Wells in this study were stimulated with as low as 2,200 lbm [1 tonne] to nearly 407,000 lbm [185 tonne] of proppant per well in one to five stages.
Analyses suggest that significantly greater economic return has been achieved when fracture designs are optimized. In this study, the most common design was 132,000 lbm [60 tonne] of proppant placed with a hydrocarbon-based fluid. For this treatment design, the average first year production for wells receiving 132,000 lbm [60 tonne] of sand was 302 MMscf [8.5 × 106 m3] of gas. Wells stimulated with 132,000 lbm [60 tonne] of ceramic proppant averaged 420 MMscf [11.9 × 106 m3] production during the first year. Benefits vary with job size, fluid type, and other factors. The incremental cost of ceramic proppant is usually recovered within 30 days, generating a significant increase in profitability. At current gas prices, average return on investment achieved by optimizing proppant selection greatly exceeds 100%.
Production from Cardium oil wells was also found to increase with proppant concentration and with proppant size. A preliminary review suggests that oil production has been significantly improved with higher conductivity fractures. While a full statistical review remains underway, the initial comparisons suggest that further increases in proppant conductivity should be considered. Additional information is provided to assist fracture optimization strategy for both oil and gas wells in the Cardium formation.
Optimal Field Development Planning of Well Locations With Reservoir Uncertainty
Authors: Cullick A. S. , Narayanan K. , Gorell S. 
Published: December 2007

Abstract
The paper presents a process for determining optimal subsurface locations for producing and injecting wells in a field to improve reservoir performance and value. The process is illustrated by optimizing well locations in an initial development planning context. The process involves planning a set of wells on a static reservoir model using an automated well planner. These locations are then optimized with dynamic flow simulation to achieve higher recovery or economic benefit. In this work, we present the framework for optimizing many well locations simultaneously, with reservoir simulation and economic analysis. This method is demonstrated byapplying it to a field-scale simulation model with water injection.
A New Method for the Determination of Foam Capillary Pressures in Porous Media
Authors: van der Net A. , Zitha P. L. J. 
Published: December 2007

Abstract
This paper reports a new implementation of X-ray computed tomography (CT) to investigate capillary pressures during foam flow in porous media. The method is based on the dependence of X-ray attenuation coefficient of gas on its pressure. Gas pressureare obtained from the CT images, together with water saturations, while water pressure is measured classically using pressure sensors. The research shows that the X-ray attenuation coefficient of a core containing gas varies linearly with gas pressure, over a wide range of pressures. A similar dependence is found in presence of irreducible water, which allows determination of the residual water saturation. More significantly, during transient foam flow in porous media the gas and capillary pressures have been determined accurately, using the newly established relation between the attenuation coefficient and pressure. The capillary pressure derived from the proposed method, reveals new aspects of foam behavior, and provides for the first time direct evidence that the secondary liquid desaturation is due to gas expansion, as was suggest in earlier studies.
Case Study: Successful Implementation of ESPs in a High-GOR, Poorly Consolidated, Corrosive Field
Authors: Guevara L. A. , Rincón P. R. , McKee J. P. , Marin H. , Sanmiguel M. , Rincon G. , Vera L. 
Published: December 2007

Abstract
This paper describes the successful experience obtained in the use of electric submersible pumps (ESP) in the production of abrasive and corrosive fluids.
The study covers 114 ESP wells completed by Harvest Vinccler, in the Uracoa and Tucupita Fields, located in the state of Monagas, Venezuela.
This artificial lift method was initiated in July of 1996. Most of the failures were due to electrical failure, erosion (sand) and corrosion problems. The initial mean-time-between-failure (MTBF) of 250 days, has improved over time to 1752 days.
The following are actions, which have improved the ESP MTBF: 1-An exhaustive study of the root cause of failure.2-A new ESP design.3-Monitoring of ESP performance.4-The use of special abrasion/corrosion resistant alloy materials in ESP components and completion equipment.5-Down-hole injection of de-emulsifiers, corrosion and scale inhibitors through capillary tubing, coupled with a well integrity monitoring program.6-Improved quality and reliability of the electrical power source.
All of these actions combined have enabled optimization of ESP applications in these fields.
This study will present the details of the actions and their results, to achieve the optimization of ESP's in Uracoa-Tucupita Fields.
Feasibility of Supercritical Carbon Dioxide as a Drilling Fluid for Deep Underbalanced Drilling Operations
Authors: Gupta A. P. , Gupta A. , Langlinais J. 
Published: December 2007

Abstract
Feasibility of drilling with pure supercritical carbon dioxide to serve the needs of deep underbalanced drilling operations has been analyzed. A case study involving underbalanced drilling to access a depleted gas reservoir illustrates the need for such a study. For this well, nitrogen was initially considered as the drilling fluid. Dry nitrogen, due to its low density, was unable to generate sufficient torque in the downhole motor. Mixture of nitrogen and water, stabilized as foam, generated sufficient torque, but made it difficult to maintain underbalanced conditions. This diminished the intended benefit of using nitrogen as the drilling fluid.
CO2 is likely to be supercritical at downhole pressure and temperature conditions, with density similar to that of a liquid and viscosity comparable to a gas. A computational model was developed to calculate the variation of density and viscosity in the tubing and the annulus with pressure, temperature and depth. A circulation model was developed to calculate the frictional pressure losses in the tubing and the annulus, and also calculates important parameters such as the jet impact force and the cuttings transport ratio. An attempt was made to model the temperatures in the well using an analytical model. Corrosion aspects of a CO2 based drilling system are critical and were addressed in this study.
The results show that the unique properties of CO2, which is supercritical in the tubing and changes to vapor phase in the annulus, are advantageous in its role as a drilling fluid. It has the necessary density in the tubing to turn the downhole motor and the necessary density and viscosity to maintain underbalanced conditions in the annulus. The role of a surface choke is crucial in controlling the annular pressures for this system. A carefully designed corrosion control program is essential for such a system. Results of this study are also important for CO2 sequestration and CO2 based enhanced oil recovery operations.
Applications of Pinpoint Fracturing in the Cooper Basin, Australia
Authors: Gilbert J. , Greenstreet C. 
Published: December 2007

Abstract
Cooper Basin reservoirs commonly contain low-permeability reservoirs that require stimulation to flow. However, conventional multi-layer stimulation techniques has been shown to leave some sands untreated and not contributing, leaving potential to further increase flow rate and reserves through the use of new technology.
Pinpoint fracturing technology allows multiple precisely-targeted fracs to be economically treated, which can increase flow rates and reserves, reduce incremental per-frac costs and significantly shorten cycle time compared to multi-stage conventional treatments
Eight wells in the Cooper Basin of Australia have been Pin-Point stimulated using coiled tubing producing a 30% increase in well productivity compared with AFE expectations. Production logs run over the fractured zones show markedly improved completion efficiency with production from the majority of Pin-Point fractured zones.
Core-to-Log Comparison—What's A Good Match?
Authors: Adams S. J. 
Published: December 2007

Abstract
It is common practice in the petrophysical community to either calibrate log porosities to core measurements or to use the porosities, permeabilities and water saturations measured on core to verify that the log interpretation models used are appropriate. This paper advocates the latter approach, since such "tested" or "verified" models are more likely to be valid away from the cored wells and intervals. Using the core data to verify the log interpretation models also allows the log and core data to be compared and the uncertainties in the log-derived properties to be quantified.
This paper describes quantitative methodologies for comparing log-derived porosities, permeabilities and water saturations with their core-based equivalents. The methodology uses the differences between the log and core-based estimates to quantify uncertainty ranges at any arbitrary level (e.g. P90, P50 and P10).
Quantitative comparisons are at their most useful when the uncertainty ranges derived can be placed within a known framework so that it is apparent whether or not the match is a "good" one. This paper uses experience gained from a number of Fields spread through a variety of Basins to show sort of comparisons are common. From this "Field experience" it is possible to determine whether or not log-to-core matches are within the expected range i.e. whether or not the match is "good". If it is not "good" then additional refinements may be required to improve the comparison to an acceptable level. In any case, the uncertainties associated with the log-derived estimates can be quantified.
In general, the mean difference between log and core porosities should be less than 0.6 p.u., that between log and core permeabilities should be less than a factor of 1.5 and between log and capillary pressure (saturation-height) based water saturations should be less than 6 s.u.
Evaluation of Equivalent Circulating Density of Drilling Fluids under High-Pressure/High-Temperature Conditions
Authors: Harris O. O. , Osisanya S. O. 
Published: December 2007

Abstract
The results of a study of the effects of the temperature and pressure conditions in high temperature/high pressure wells on drilling fluid equivalent circulating density and consequently bottom-hole pressure are presented in this paper. High temperature conditions cause the fluid in the wellbore to expand, while high pressure conditions in deep wells cause fluid compression. Failure to take these two opposing effects into account can lead to errors in the estimation of bottom-hole pressure. The rheological behavior drilling fluids is also affected by the temperature and pressure conditions.
A simulator called DDSimulator was developed to simulate the wellbore during circulation. A Bingham plastic model was employed to express the rheological behavior of the drilling fluids studied, with rheological parameters expressed as functions of temperature and pressure. The Crank-Nicolson numerical discretizing scheme was employed in the DDSimulator for the evaluation of the wellbore temperature profile. The results of the simulation show that higher geothermal gradients lead to lower bottom-hole pressure. The inlet pipe temperature did not have a significant effect on the bottom-hole temperature and pressure, and higher circulation rates result in lower bottom-hole temperature and higher bottom-hole pressure.
Three-Dimensional Modeling of the Evaporation of Volatile Hydrocarbons from Heterogeneous Porous Media
Authors: Yiotis A. G. , Tsimpanogiannis I. N. , Stubos A. K. , Yortsos Y. C. 
Published: December 2007

Abstract
Lean gas injection has been considered as a process to improve the recovery of bypassed volatile oils from the matrix of fractured reservoirs. The characterization of flow and mass transfer in fractured reservoirs is a challenging task, due to the complexity of the pore space, the heterogeneity in the permeability of the rock, as well as the complex interplay between capillary, viscous and buoyancy forces. In the present paper we study the effect of heterogeneity. We develop a three-dimensional pore-network simulator that accounts for evaporation and diffusion of the volatile liquid trapped in heterogeneous pore networks. A series of numerical simulations are performed in common types of natural porous media.
We investigate the effect of permeability gradients on the saturation profile, the recovery rates of the trapped liquid clusters, the evaporation patterns and the stability of the receding evaporation front. The case of a negative permeability gradient (high permeability close to the fracture, low permeability far away) leads to a stable evaporation front. Conversely, the effect of positive permeability gradients (low permeability close to the fracture, higher permeability far away) leads to a fingered pattern, that results in lower recovery times due to higher liquid saturation at the product surface. The paper finds application to problems of evaporation or drying of volatile liquids or other liquids from porous media. These arise in enhanced oil recovery in fractured systems, as well as in the remediation of contaminated soils.
Alternative Approaches to Real Option Valuation: A Critical Appraisal
Authors: Wilkinson D. , Bailey W. J. , Couët B. 
Published: December 2007

Abstract
Recent years have seen numerous management and petroleum-related articles on the application of financial option techniques to valuation of real assets under uncertainty and operational flexibility. However, universal acceptance of this methodology has been elusive or even resisted. Such reluctance is understandable, as many inconsistencies exist in the various methodologies. Part of the problem is that, although each proposed method provides an answer (the calculated value), the precise meaning of this value is unclear. In this work, we suggest an operational definition of the real option price, and a criterion for deciding whether a given method generates an answer that agrees with this definition. We then consider two real option methodologies: multi-lattice and consolidated. The former retains the fundamental degrees of freedom of the problem, while the latter combines all uncertainties into a single effective volatility. The methods are analyzed in terms of a simple oilfield salvage option. It is observed that part of the discrepancy between the methods is caused by a general difference in valuation techniques, one that is not specific to the optionality of the problem. When the consolidated method is revised so that the two methods give the same value of the project in the absence of optionality, the option values are in reasonable agreement with each other.
Effect of Downhole Pressure Conditions on High-Power Laser Perforation
Authors: Gahan B. C. , Batarseh S. , Watson R. , Deeg W. 
Published: December 2007

Abstract
Researchers at Gas Technology Institute (GTI) have been exploring the use of high power laser energy as a non-damaging alternative to conventional explosive perforation methods. All previous laser/rock interaction tests were performed on samples in the lab at atmospheric pressure. To determine the effect of downhole pressure conditions, a sophisticated tri-axial cell was designed and tested. For the first time, Berea sandstone, limestone and clad core samples were lased under various combinations of confining, axial and pore pressures. Clad core samples consisted of steel cemented to rock in an effort to represent material penetrated in a cased hole. The results of this experiment will assist in the development of a downhole laser perforation prototype tool.
In the past, several combinations of laser and rock variables were investigated at standard conditions and reported in the literature. More recent experiments determined the technical feasibility of laser perforation with a 5.34 kW Ytterbium-doped multiclad fiber laser exposed to multiple samples of rock, cement and steel. The fiber laser was capable of penetrating these materials under a variety of conditions, to an appropriate depth, and with reasonable energy requirements. It was determined that fiber lasers are capable of cutting rock without causing damage to flow properties. Furthermore, the laser perforation resulted in permeability improvements on the exposed rock surface.
This paper will discuss the design and development of a customized laser pressure cell; experimental design and procedures, and the resulting data on pressure-charged samples exposed to the laser beam. An analysis will provide the resulting effect of downhole pressure conditions on the laser/rock interaction process.
Fundamental PVT Calculations for Associated and Gas/Condensate Natural Gas Systems
Authors: Sutton R. P. 
Published: December 2007

Abstract
Problems with existing procedures used to estimate gas PVT properties are identified. The situation is reviewed and methods proposed to alleviate these problems. Natural gases are derived from two basic sources - associated gas which is liberated from oil and gas condensates where hydrocarbon liquid, if present, is vaporized in the gas phase. The two gases are fundamentally different in that a high gravity associated gas is typically rich in ethane through pentane while gas condensates are rich in heptanes-plus. Additionally either type of gas may contain nonhydrocarbon impurities such as hydrogen sulfide, carbon dioxide and nitrogen. Failure to properly distinguish between the two types of gases can result in calculation errors in excess of those allowable for technical work. Sutton investigated high gravity gas condensate gases in 1985 and developed methods for estimating pseudocritical properties which resulted in more accurate Z factors. The method is suitable for all light natural gases and gas condensate gases. It should not be used for high gravity hydrocarbon gases that do not contain significant levels of heptanes-plus. The original Sutton database of gas condensate PVT properties has been expanded to 2264 gas compositions with over 10,000 gas compressibility factor measurements. A database of associated gas compositions containing over 3200 compositions has been created to evaluate suitable methods for estimating PVT properties for this category of gas. Pure component data for methane, methane-propane, methane-n-butane, methane-n-decane and methane-propane- n-decane has been compiled to determine the suitability of the derived methods. The Wichert55 database of sour gas compressibility factors has been supplemented with additional field and pure component data to investigate suitable adjustments to pseudo-critical properties that ensure accurate estimates of compressibility factors. Mathematical representations of compressibility factor charts commonly used by the engineering community and methods used by the geophysics community are investigated. Generally these methods are robust and have been found suitable for ranges beyond those originally recommended. Natural gas viscosity, typically estimated through correlation, has been found to be inadequate for high gravity gas condensates requiring revised procedures for accurate calculations.
Combined Seismic and Production History Matching
Authors: Khazanehdari J. , Curtis T. , Yi T. 
Published: December 2007

Abstract
Production history matching in isolation can result in several nonunique realizations of reservoir parameters; using this practice only modifies the reservoir in the drainage region of the measurement wells. In early production and in fields with a low density of producing-well coverage, production history matching is particularly erroneous. By constraining the production history matching with time-lapse seismic data, a faster convergence to a better solution with reduced uncertainty can be achieved. The repeat acquisition of three-dimensional (3D) seismic data, commonly known as "time-lapse" seismic reservoir monitoring or four-dimensional (4D) data acquisition, is based on the fact that reservoir production and injection significantly change the reservoir's fluid saturation, pressure, and temperature. This subsequently alters the acoustic response of the reservoir rock that can be detected using the seismic method.
Combined seismic and production history matching was conducted on a small segment of a reservoir model from a North Sea hydrocarbon field, using software which could simulate changes in the reservoir. The selected segment for modeling consisted of a producing well and an injector well. The existence of several repeated 3D high-resolution seismic datasets provided a unique opportunity to carry out a combined time-lapse and production history matching. A quantitative 4D fluid saturation and pressure mapping technique allowed calibration of 4D seismic responses coupled with flow simulator models.
The modeled results, using production history matching alone, were poor, predicting low water cut, where in fact, the water cut was as high as 60%. The combination of seismic data and production history matching resulted in a better prediction and quicker convergence to a solution that more closely matched both the calibrated seismic and the production data.
The successful results from the integrated and quantitative approach described in this paper demonstrate a potential for the future integration of seismic and reservoir data to deliver improved reservoir production and reservoir management.