bluuebunny/crossref_metadata_2025_split huggingface dataset:
Oil and Gas Property Marketing: To "e" or not to "e"
Authors: Marko William A. , Roberts Geoffrey G. 
Published: December 2007

Abstract
This paper is written not from the perspective of a service provider, but from the point of view of a seller of oil and gas properties. It is a pragmatic discussion of the application of e- business now and in the future for oil and gas property acquisitions and divestments (e-A&D). Its focus is not on specific technologies, but rather on how technology, judiciously applied, can improve A&D processes with the bottom-line measure being-an improved bottom line for oil and gas companies.
The Determinants of Oil and Gas Reserves Additions: Empirical Evidence from the U.S. Gulf of Mexico Outer Continental Shelf (OCS) Region from 1977 to 1998
Authors: Iledare Omowunmi O. , Pulsipher Allan G. 
Published: December 2007

Abstract
This paper presents a model of new petroleum reserves in the Gulf of Mexico OCS region from 1977 to 1998&lt;SUP&gt;1&lt;/SUP&gt;. The model has three distinct components: the effectiveness of drilling at finding reserves (drilling success rate), the effectiveness of successful drilling at adding new petroleum reserves (petroleum productivity rate), and the number of wells drilled to find new reserves (drilling rate). Each component is specified as a function of several competing factors to determine the extent to which each determinant affects reserve additions on the OCS. The model equations are estimated using OCS data on reserves and oil and gas wells drilled from 1977-1998. The empirical results indicate a statistically significant evidence of diminishing returns as drilling increases on the OCS. The estimated elasticities of oil and gas reserves additions with respect to resource depletion are both very elastic. However, the responsiveness of new oil and gas reserves to economic incentives is significantly inelastic for oil and gas reserves. The results show that the average impact of technical change, economic, resource depletion, and prospect highgrading on oil reserve additions is a net gain of about 9.2% per year between 1977 and 1998. However, the net annual average impact of these competing factors on new non-associated gas reserves is a decrease of 3.3 percent per year.
Synergy through Seismic Attributes in Reservoir Management-a Case Study
Authors: Mitra Partha P. , Singh Kharak 
Published: December 2007

Abstract
The heterogeneity within a reservoir is difficult to predict, but the subtle changes of the seismic wave shape within any sequence provide valuable information about the reservoir and are preserved in 3D seismic data. In order to optimize the understanding of the reservoir, it is necessary to integrate geophysical, geological, petrophysical, reservoir and production data. Diagnostic tests and studies such as production logging, reservoir saturation, build up, pressure and temperature are commonly studied at the time of reservoir management in a developing field but off late seismic attribute is being used as an additional tool for reservoir management. With the advent of sophisticated algorithms and faster machines, today it is possible to extract a number of seismic attributes from within a particular sequence. In a heterogeneous reservoir or in an area of poor well control, synergistic study of seismic attributes can help us investigate the lateral variations in the quality of the reservoir and improve the imaging of reservoir units, providing vital clues for placing infill wells and injectors.
In the present study an attempt has been made to decipher the reservoir behavior in one of the western offshore fields of India. The field in question is in production from carbonate reservoir over last six years. At places, poor reservoir facies have been observed within the pay leading to poor transmissibility in the area thus affecting the voidage compensation in the targeted zone. Using the conventional tools, it was difficult to map the lateral facies changes in between wells. Efforts have been made to calibrate seismic attributes with other relevant data in order to arrive at a good prediction of the reservoir quality.
The Influence of Variations in Porosity and Water Saturation on the Success of Hydraulic Fracturing: A Semi-theoretical Analysis
Authors: Widarsono B. , Muladi A. , Saptono F. 
Published: December 2007

Abstract
The objective of the study presented in this paper is to observe the influence of variation in rock petrophysical properties on fracture development. The analysis was primarily conducted using the combination of Continuum Damage Mechanics and the Perkins-Kern-Nordgren model (CDM-PKN). Essentially, the effect of porosity, water saturation, and shale contents on the two rock mechanical properties was studied using well-log data from an oil well in Central Sumatra (sandstone). Prior to the study the data was modeled using a combination of theory of elasticity, Gassmann theory of acoustic velocity propagation, and standard log interpretation. Laboratory acoustic velocity measurements were carried out to provide required data. The resulting model-relationships between sonic velocity, Poisson ratio, porosity, water saturation, and shale contents serve as input data for the study, on which the application of CDM-PKN model show that fracture length and width are mostly affected by variation in porosity. Variations in porosity between 11 % and 20 % may result in changes of up to 18 % and 100 % in fracture length and width, respectively. In contrast, variations in fluid saturation and shale contents (max. 10 %) exhibit less influence to the fracture growth. Nevertheless, depending on reservoir fluid and clay types, omission of the latter two factors in any hydraulic fracture design could complicate the mis-prediction.
Experimental Investigation into Revaporization of Retrograde Condensate by Lean Gas Injection
Authors: Luo Kai , Li Shi , Zheng Xitan , Chen Gang , Dai Zhijian , Liu Ning 
Published: December 2007

Abstract
Re-injection of produced gas is a common strategy to maintain pressure and to meet environmental regulations in gas condensate reservoirs and also to store gas until the market available. Although the best idea to prevent liquid loss is the full pressure maintenance development above the dew point pressure, the partial pressure maintenance process below dew point may be desirable for economic reasons, as the dew point pressures in some gas condensate reservoirs discovered in recent years is very high. In this case one major concern is whether gas cycling above the dewpoint is more profitable than below the dewpoint. Therefore, a knowledge of accurate condensate recoveries under two different development schemes is vital for making the accurate economic assessment and making final decisions.
To the end, a series of experiments have been done to investigate the condensate recovery based on the above two different development strategies and quantitatively determine the revaporization efficiency of retrograde condensate by lean gas injection. First the gas injection below the dewpoint was performed in a long-core apparatus. In order to calculate the quantitative amount of the revaporized condensate, other two parallel tests of gas injection above the dew point in a long core system and gas injection below the dew point in the PVT cell were conducted as a comparative basis. The actual gas condensate fluid and a long core system are employed here. The gas condensate used is rich and highly waxy. As a complete study, the routine phase behavior is first detailed, including constant mass expansion and constant volume depletion. An interesting finding in PVT cell shows that lean gas can not only effectively revaporize the intermediate but also C20 plus components. Comparison of the tests in long-core system illustrates that more condensate above the dewpoint is recovered than below the dewpoint. This is consistent with the conventional idea that the full pressure maintenance is superior to the partial pressure maintenance according to the condensate recovery. It should be noted that all the condensate recoveries reported here in three runs don't include the additional withdrawal of condensate in the slowdown process to abandonment pressure.
Upscaling of Flow Units for Reservoir Flow Incorporating Small-Scale Heterogeneities
Authors: Mikes D. , Barzandji O. H. M. , Bruining J. , Geel C. R. 
Published: December 2007

Abstract
Small-scale heterogeneities have a significant effect on the behaviour of fluid flow through a reservoir, since capillary forces trap the non-wetting phase in the high-permeable parts of a water-wet porous medium. An upscaling procedure must therefore be able to account for reservoir structure as well as for relative permeabilities and capillary pressures on the lamina scale.
For the geological model we propose a five-scale hierarchy with crossbed and subfacies as key elements: i.e. lamina scale → flow cell scale → flow unit scale → facies scale → reservoir scale. The reservoir model is a simplified version of the geological model with the flow cell and flow unit as building blocks. As an example we take a model of a meandering river with three types of flow units, viz. channel, pointbar, and floodplain. Each of these consists of one type of flow cell, i.e. trough crossbedding, longitudinal bedding and horizontal bedding, respectively (Fig. 2).
We propose a four-step procedure (Fig. 1): (1) Assignment of flow cells and flow units; (2) Calculation of capillary pressures and relative permeabilities of laminae; (3) Steady state flow simulation on flow cells; (4) Assignment of the ensuing effective phase permeabilities and capillary pressures to the flow units. The macro reservoir has the flow units as building blocks.
We use lamina permeabilities either from our strongly improved probe-permeameter or from a database. We calculate lamina scale capillary pressures and relative permeabilities using Brooks-Corey and Leverett-J function. Upscaling is realized using flow simulation: A microsimulation is performed on each flow cell for a number of water/oil injection ratios. The ensuing upscaled relative permeabilities are anisotropic and flow-rate dependent. They are used as the constitutive relations for the flow units, which is the next superior level to the crossbed.
This model and its properties are incorporated into the simulation of the full reservoir described in the SPE ninth comparative study on black oil simulators in heterogeneous reservoirs. We will ignore the rate dependence and use a constant anisotropy factor in each flow unit. The result shows that small-scale heterogeneities characteristic of the various flow cells must be specifically taken into account. Our procedure provides a method to accomplish this. The method is easy to implement.
A Comprehensive Study of the Relative Dielectric Permittivity in Porous Media
Authors: Garrouch Ali A. 
Published: December 2007

Abstract
This study investigated the effects of water saturation and wettability on the dielectric permittivity experimentally, using four-electrode impedance measurements, and theoretically, using models that account for the electrical double layer polarization.
Complex impedance measurements, performed on Berea sandstone and on Ottawa-sand packs in the frequency range 10 Hz to 1 MHz, indicated a linearly varying relative dielectric permittivity with water saturations above 50%. The rate of change of the relative dielectric permittivity with saturation decreased as the frequency increased.
The relative dielectric permittivity of water-wet samples was higher than that of the oil-wet samples at all water saturations. The difference was more pronounced as the saturation increased. The relative change was approximately 60% at a water saturation of 100%. To confirm these experimental observations, this study conducted simulations of rock wettability changes using a generalized Maxwell-Wagner model by varying the amount of ionic surface charge of rocks. In general oil-wetting agents react with the formation matrix by connecting their positively charged tails to the negatively charged silica surfaces, lowering the surface charge density. Simulations showed that there was about an order of magnitude difference in the relative dielectric permittivity as the rock surface charge changed by an order of magnitude. Both simulations and experimental results showed a trend of significant increase in the relative dielectric permittivity as the rock conditions changed from oil-wet to water-wet.
A Rule Induction Algorithm for Application to Petrophysical, Seismic, Geological and Reservoir Data
Authors: Deutsch Clayton V. , Xie YuLong , Cullick A. Stan 
Published: December 2007

Abstract
This paper introduces an algorithm for rule induction intended to provide new insights, improve the reliability and expedite the utilization of large petrophysical and geologic databases. Very large petrophysical, geophysical, and geological databases contain multiple data types, which must be interpreted for application in subsurface modeling. This paper presents a significant advance in discovering complex and even nontrivial data relationships from such databases.
Geoscientists are often challenged to predict subsurface lithologies and properties from multivariate relationships within large databases of core, wireline, and seismic data. Many data analysis techniques are used including histograms, parametric and non-parametric regression, n-dimensional histograms, cluster analysis, discrimininant analysis, principal components analysis. This paper introduces a new algorithm that seeks to discover "rule-like" relationships within the data that can be used to make predictions. The method is loosely derived from a data mining technology of classification.
Concepts of data attribute distinguishability and importance are introduced to assess the value of the data and the outcomes to predictability. The new theory, implementation details, and an application are presented. Current petrophysical, seismic, and geostatistical analysis benefit from the rule induction algorithm presented. Improved reservoir characterization and forecasting result.
Slug Development/Dissipation in an Inclined Pipeline with Changing Pipe ID
Authors: Lin Chew-Chen 
Published: December 2007

Abstract
Heavy oil recovery efficiency is strongly dependent upon quality and rate control of two-phase steam in a distribution system. One of the major challenges in steamflood operations is unequal steam phase-splitting at a pipe junction in the steam distribution system. As a result, the proper quantity of latent heat is not always effectively delivered to injection wells for optimized production. To overcome such a problem, a device referred to as the SpliTigator, is installed at branches in a steam distribution system. The standard SpliTigator was de-signed to perform best with a stratified flow regime, because water-vapor separation can be guaranteed if stratified flow arrives at the inlet of the SpliTigator. However, slug flow caused by a hilly terrain pipeline can occur at the inlet of the SpliTigator, practically eliminating its ability to mitigate the steam phase-splitting problem. A remedy can be implemented by modifying the piping configuration to alleviate severity of slug flow.
Experiments were conducted in the air-water flow loop to investigate slug development and dissipation along an inclined pipeline. Furthermore, tests were done for studying slug dis-sipation with increased pipe ID in the downstream section. Test data were analyzed by calculating slug frequency and slug length ratio as a slug development/dissipation index. Presented in this report are experimental results that illustrated sensitivity of slug dissipation to inclination angles and down-stream pipe ID. Evidenced in this study, modifying piping configuration by increasing downstream pipe ID and/or increasing downward inclination angle is a method of mitigating terrain induced slug before its arrival at the inlet of a SpliTigator.
Using Integrated Information to Optimizing Matrix Acidizing
Authors: Zhu D. , Radjadhyax N. , Hill A. D. , Montgomery C. T. 
Published: December 2007

Abstract
The technology of matrix acidizing has advanced dramatically over the last 30 years. Models have been developed to help understand and design the process, and methods have been applied in the field to monitor and evaluate treatments to achieve stimulation results as expected. Despite these advances, the success rate of acidizing is still low (estimated to be 50% - 70%), particularly in sandstones. When an acid treatment fails, not only will it waste the cost of the treatment, but also may possibly cause further damage to the well and lead to more severe problems.
Acidizing success strongly depends on the susceptibility of nearwell formation damage to removal by the acid solution. Thus, the nature of the damaging material and the depth to which the damage penetrates into the formation are critical properties to the success of acidizing treatments. Predicting the outcome of a treatment using models of the process depends most strongly on the description of the damaged region provided to the model. The dilemma we face is that we seldom have a detailed knowledge of the damage, but instead only a global measurement of the skin factor of the well. In this paper, we present an approach to improve the success rate of matrix acidizing by using integrated formation damage models, sandstone acidizing models, skin evolution models, and well production information. The theoretical prediction of the well response to an acid treatment is compared with a skin analysis result obtained during the treatment. Problems with inappropriate treating fluids can be identified clearly with increased skin factor during certain injection periods. Damage depth and damaged permeability can be re-evaluated from the characteristics of the well response to the acid. The skin analysis result can be confirmed with the well production or injection data after acidizing. Using the improved description of the damage obtained from the skin analysis of treated wells, the simulation model can then be used to redesign acidizing treatments to achieve better results.
Formation Pressure Integrity Treatments Optimize Drilling and Completion of HTHP Production Hole Sections
Authors: Sweatman Ron , Kelley Scott , Heathman James 
Published: December 2007

Abstract
Insufficient borehole pressure integrity (BHPI) is a significant drilling challenge in deep, high-temperature, high-pressure (HTHP) wells in south Texas, as it is in many wells. Shales and/ or sands weakened by depletion, leaking faults, or unfavorable rock properties result in lost returns when mud weights are close to pore pressures. In one field, short (~50 ft) transitions from normal (11 lb/gal) to overpressured (17.5 to 18.0 lb/gal) Frio formations compound the severity of this challenge. Setting casing to isolate normal-pressure from high-pressure zones can be problematic if faults exist at the casing shoe and/or the cement job does not provide a good hydraulic seal. In one case, the intermediate casing shoe failed to test, and conventional cement squeezes were unable to correct the problem. In the productive portion of the well, preventing skin and or formation damage in an interval that had a wide range of pore pressures (8.5 to 17.8 lbm/gal), was a major concern with any treatment option to increase borehole integrity.
This paper describes successful applications of new BHPI treatment materials and methods for increasing borehole integrity. BHPI treatments have allowed higher drilling and cementing circulation rates. This has helped optimize drilling performance and improve well conditions during cementing operations, which has resulted in improved primary cementing success. It has been suggested that skin damage in the zones of interest can be minimized since BHPI treatments can be designed and targeted to only enter areas with low BHPI. In one case, a BHPI treatment entered a low-pressure productive interval, which, after a planned stimulation program, did not seem to affect production performance. In another case, after BHPI treatments helped increase wellbore integrity, the productive interval in one well was successfully cemented without requiring a drilling liner, which would have limited completion flexibility.
A theoretical rock mechanics model is discussed to help explain how the new BHPI treatments can rapidly and substantially increases the pressure integrity of holes located across both sand and shale formations. Minor BHPI filtrate invasions during tests in high and low-permeability sandstone cores should explain why the new BHPI system also limits formation damage.
Development and Application of Surfactant-Based Systems for Treatment of Wells Drilled with OBM
Authors: Giard-Blanchard Claire , Audibert-Hayet Annie , Dalmazzone Christine 
Published: December 2007

Abstract
Wells drilled with oil-based muds can suffer from severe damage which decreases their overall productivity. During drilling, mud solid parts tend to form an external and internal filtercake along well bore through filtration, while liquid part (filtrate) tends to leak off into the formation. Clean-up process is then necessary to restore the productive zone to a nearnatural state before production. Chemical treatment is often used to break external cake and to wash-off damage zone around well bore, so that formation recovers its fluid transfer properties (water, oil).
This paper focuses on the development and application of surfactant-based systems for treatment of wells drilled with oil-based muds. Aqueous based systems are widely used in such cases to effect significant production increases, but they create an additional damage which may even block oil production. A promising issue would be to use a surfactant-based system in a non-pollutant organic base to limit in situ formation of emulsion and water saturation around the well bore.
Though, our research methodology aims to select an organic-based surfactant system able to break the cake formed by filtration of a given oil-based mud system. The demulsifying formulation should be able to bother interface surfactants stabilizing effect to allow water droplets coalescence inside the cake. Through breaking emulsion inside the cake, surfactants may decrease cake cohesion and bore adherence. Careful choice may help preventing the system composed of filtrate, reservoir fluids and treatment fluid from forming a stable emulsion inside the porous medium, which could block oil production. Laboratory data are presented showing the relative effects of the organic phase surfactant system and of a conventional commercial treatment on cake destruction and productivity recovering. Results are held by a precise experimental methodology combining Differential Scanning Calorimetry and Cryomicroscopy. Both techniques characterize emulsion stability and destabilization as a function of wellbore parameters (contact time, overbalance pressure...).