bluuebunny/crossref_metadata_2025_split huggingface dataset:
Aspects of Multicomponent Resistivity Data and Macroscopic Resistivity Anisotropy
Authors: Schöen J. H. , Yu Liming , Georgi D. T. , Fanini O. 
Published: December 2007

Abstract
New induction logging hardware makes it possible to obtain both resistivity and resistivity anisotropy data. Resistivity anisotropy, the ratio of vertical to horizontal resistivity is the macroscopic effect of thinly layered formations in which logging tools have insufficient vertical resolution to properly resolve the individual beds or laminae. Generally, there are two types of layering: Laminated shaly sands. The sediment consists of thin bedded sand-shale sequences (anisotropy in these sands originates from the contrast of shale and sand resistivity).Finely layered anisotropic sands. The sand is composed of layers of different grain sizes and/or sorting (anisotropy in these sands originates from the resistivity contrast associated with the different water saturation).
The interpretation of conventional resistivity data is well understood. However, interpretation of vertical resistivity and resistivity anisotropy is not well understood and often counterintuitive. We have used forward modeling to illustrate the effects of porosity variability in layered formations. For example, we have investigated the porosity layering effect, which varies from an average porosity of 20 p.u. by +/- 5, 10, 15 p.u.. Three types of layering were considered: graded bedding, square- and sin2-variation of porosity with depth. The modeling shows that sharp bed boundaries create the maximum resistivity anisotropy for any two component resistivity distributions.
The new induction logging hardware is comprised of three mutually orthogonal transmitter-receiver coil configurations measuring all necessary data to derive both resistivity and resistivity anisotropy of the formation in vertical, deviated, and horizontal wells. Simple models illustrate the physics and the tools' capabilities are demonstrated with a synthetic example. Based on the petrophysical analysis of porosity contrast and layering type, a resistivity model is constructed and the tool responses of this model are computed. Using state-of-the-art inversion techniques, both resistivity and resistivity anisotropy can be recovered.
Measurements and Simulation of Inertial and High Capillary Number Flow Phenomena in Gas-Condensate Relative Permeability
Authors: Mott Robert , Cable Andrew , Spearing Mike 
Published: December 2007

Abstract
The productivity of most gas condensate wells is reduced significantly by condensate banking when the bottom hole pressure falls below the dew point. The most important parameter for determining condensate well productivity is the effective gas permeability in the near well region, where very high velocities can occur. An understanding of the characteristics of high-velocity gas-condensate flow is necessary for accurate forecasts of well productivity.
A number of laboratory experiments have demonstrated that gas condensate relative permeabilities increase at high velocity, reducing the negative impact of condensate banking on well productivity. On the other hand, inertial (non-Darcy) flow effects can reduce the effective gas permeability and lead to lower productivity.
This paper presents results of relative permeability measurements on a low permeability sandstone core, using a 5-component gas-condensate fluid. The experiments used a pseudo-steady-state technique at high pressure and high velocity, measuring relative permeability under conditions similar to the near-well region of a gas-condensate reservoir.
By carrying out measurements at a range of interfacial tensions and velocities, the results can be used to distinguish between high capillary number and inertial flow effects, and to quantify the impact of these two conflicting phenomena. The experiments suggest that the inertial flow coefficient in a 3-phase gas-condensate-water system is about 50% higher then in the equivalent 2-phase gas-water system.
The results of these experiments have been modelled through a correlation of relative permeability versus capillary number, together with an inertial flow correction to the gas permeability. The paper discusses these models and demonstrates how they can be used to calculate gas-condensate well performance in full-field reservoir simulation.
Development of a Through-Flow-Line TFL-Deployed Insert Surface-Controlled Subsurface Safety Valve
Authors: Abou-Sayed Omar A. , Reeves Harold J. , Valencia Randy L. , Holcombe Gary D. 
Published: December 2007

Abstract
BP Amoco’s Pompano Phase II subsea development is located in the Gulf of Mexico in Block 28 of the Mississippi Canyon. The water depth is approximately 1,865 feet. The subsea template is tied back 4.5 miles to the Pompano platform located in Vioska Knoll Block 989. Phase II development is a 10-slot, integrated template/manifold.
When the tubing retrievable safety valve (TRSV) in the primary and secondary production bores in two of the subsea wells failed, the wells had to be shut-in. An innovative through-flowline (TFL)-deployed insert surface-controlled subsurface safety valve (ISCSSV) enabled BPAmoco to restore operability and integrity to these wells. Root cause analysis had determined that declining reservoir pressures leading to excessive control-line differential pressures compromised at least of at least one of the tubing retrievable safety valves run with the original completions in 6 of the 8 subsea wells. Several options for remediation were considered: Floating rig interventions at an estimated cost of $610MM per well, orCodevelopment with an oilfield engineering/service company of a TFL-deployed insert SCSSV.
The second option was chosen, and involved both design work, as well as a rigorous test program.
The development and installation of these inserts allowed production in two subsea shut-in wells to be restored. This operation was the first in the Gulf of Mexico in which a TRSV lockout and the insert of a 3-in. insert flapper safety valve was deployed. BP Amoco’s TFL requirements have led to significant enhancement of TFL technology in general, and the maturation of this project was able to provide BPAmoco with capability to realize a substantial saving in operating costs.
The Significance of Risk Definition on Portfolio Selection
Authors: McVean J. R. 
Published: December 2007

Abstract
Efficient frontier portfolio analysis considers the balance between value and risk in the selection of "optimal" portfolios. Efficient frontier theory was originally developed for the realm of securities portfolios, where considering risk and uncertainty as synonymous may be appropriate. However, the appropriateness of this assumption has come to be questioned for petroleum portfolios. By examining the possible portfolios made up of a subset of 30 fictional but realistic projects, the significance of the definition of risk is explored. For each project, several risk profiles were generated based on different measures of value using Monte Carlo simulations. The definitions of risk that are explored include the standard deviation of the portfolio’s risk profile, the semi-standard deviation of the risk profile, the tenth percentile of the risk profile, and the probability of the measure of value being less than a specified threshold. The impact of risk being based on measures of value other than that used as the principal value measure is also explored. The conclusion is that the selection of an "optimal" portfolio is strongly dependent on which definition of risk is selected. Consequently, it is important to explore multiple risk definitions in order to more fully understand the quality of a portfolio, and ultimately make wise decisions as to which projects should be pursued.
The Magnetic Resonance While-Drilling Tool: Theory and Operation
Authors: Prammer M. G. , Drack E. , Goodman G. , Masak P. , Menger S. , Morys M. , Zannoni S. , Suddarth B. , Dudley J. 
Published: December 2007

Abstract
The first Magnetic Resonance While-Drilling (MRWD) tools have been built and field tested. The hardware was designed to provide data compatible with the Magnetic Resonance Imaging Log (MRIL®) wireline tool in terms of processing and interpretation. The paper discusses the theory of robust MRIL measurements in the drilling environment and reviews the theory of T1 measurements. We report on the results of a field test in the Gulf of Mexico. The MRWD device logged the entire TD run from casing to TD and provided additional hydrocarbon-typing data in wiping mode over the target zones. Wireline MRIL data and conventional logs were used to verify the MRWD measurements.
Integration of Geology, Geophysics, and Numerical Simulation in the Interpretation of A Well Test in a Fluvial Reservoir
Authors: Raghavan R. , Dixon T. N. , Robinson S. W. , Phan V. Q. 
Published: December 2007

Abstract
The focus of this paper is the incorporation of geologic and geophysical data in the analysis of pressure tests in a fluvial reservoir. Using a 3,105,851 cell ‘porosity cube’ derived by seismic and well-log data, this work outlines the steps involved in developing a three-dimensional model with 7,128 cells that was used to estimate reservoir properties (permeability, skin, permeability-porosity relationship, reservoir connectivity, fault factor, etc.). The principal steps involved in developing the reservoir model include: identifying all points in the ‘porosity cube’ that were connected to the wellbore with porosities above a specified cutoff to identify the high- porosity channels and low-porosity overbanks,upscaling the ‘porosity cube’ to a reasonable size for welltest simulation while preserving pay thickness, pore volume, connectivity between high- and low-porosity materials, etc.,matching the observed pressure and pressure-derivative responses using a numerical simulator and a regression program to automatically adjust the reservoir permeability description.
A well test in a gas condensate reservoir is used to demonstrate the ideas outlined in this work. This approach allowed us to identify not only horizontal permeability but also vertical permeability. The issues that need to be considered and the conclusions that are derived on the basis of this work, differ significantly from conventional interpretations.
Gas Injection in Paleo Oil Zones
Authors: Skauge Arne , Hydro Norsk , Surguchev Leonid 
Published: December 2007

Abstract
In many large oil fields low oil saturation transition zones encompass significant hydrocarbon volumes. In some fields this retained oil below the water-oil contact in the water column is referred to as paleo oil. Gas injection represents one of the potential recovery methods to mobilize, displace and produce this remaining oil from transition zones.
The simulation model was built using geological description characteristic for the oil field water zone. The reservoir model for the water column above paleo water-oil contact was established based on core and log data from two wells. Down dip gas injection with vertical and horizontal wells was evaluated for drainage and recovery of paleo oil.
CO2 injection has been compared to flue gas and hydrocarbon gas. The immiscible or developed miscibility by CO2 injection process was more efficient due to compositional effects such as vaporization and swelling. Compositional simulation with fine grid vertical resolution in the reservoir model was performed. A large number of hydrocarbon components in the fluid description (17) were used in order to account properly for vaporization, swelling and gravity effects. The remaining oil saturation in the paleo zone may be significantly reduced by secondary and tertiary CO2 injection.
Simulations confirmed the formation of the tertiary oil bank and updip oil displacement. The CO2 liquid fraction in the oil bank reaches a level of about 50%. The oil viscosity in the moving oil bank is reduced significantly by dissolved CO2 compared to the viscosity of the original oil.
Simulations showed that high oil recovery factors could be achieved by gas injection in the transition paleo zone. The injection/production strategies can be further optimized to reduce high water-cut production period.
Real-Time Determination of Filtrate Contamination During Openhole Wireline Sampling by Optical Spectroscopy
Authors: Mullins Oliver C. , Schroer Jon 
Published: December 2007

Abstract
The key objectives of openhole wireline sampling are to identify desired fluids and to collect representative formation samples. Optical methods such as visible – near-infrared spectroscopy (NIR) are used to identify and quantify mixed oil, water, and gas flows in-situ during wireline logging. In wells drilled with oil based muds (OBM) or synthetic based muds (SBM), differentiating crude oil from the filtrate base fluid is critical. The widely used current practice is to measure the increase in fluid coloration (by NIR) vs. time to qualitatively assess the increasing fraction of crude oil with pumping time. Here, we describe new methods of utilizing NIR log data to provide quantitatively during sampling the %-OBM contamination in the extracted fluid. In addition, these methods allow prediction of contamination at future times during the sampling job, thereby determining the effectiveness of further pumping. The significant improvement in sampling efficiency is demonstrated with several log examples. Finally, using our methods, mud performance in the downhole environment can be monitored and optimized in subsequent jobs.
Equation of State of a Complex Fluid Column and Prediction of Contacts in Orocual Field, Venezuela
Authors: Smith Richard W. , Bard Wade A. , Lugo Claudia , Yemez Ivan , Guerini Agostino , Whitson Curtis H. , Fevang Øivind 
Published: December 2007

Abstract
Diligent management of a high-pressure gas injection program in a field with a complex column of hydrocarbon fluids requires reservoir modeling. It is important and necessary to perform a detailed study of the PVT samples including the evaluation of the fluid distributions and to define an equation-of-state (EOS) to be used in a reservoir model.
The Orocual field is located in the northern Monagas state of Venezuela and is owned and operated by Petroleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela. The field is characterized as a complex structure having more than 3000 feet of vertical hydrocarbon column. Fluids change from light gas in the top of the structure to condensate gas, to a near-critical transition fluid and volatile oil, to under-saturated oil at the bottom of the column.
Reservoir compartmentalization adds complexity to the field and structurally equivalent, non-communicating fluid regions exist. The dispersion of some sample characteristics versus depth was thought to be the result of non-representative samples. The ability to integrate the PVT data into the geological model adds another dimension in defining the structural complexities.
The paper demonstrates a technique to identify representative samples for use in developing an EOS, and for initializing fluids in place. A method is presented to adjust the component composition versus depth, providing consistent vertical composition distribution and compositional model stability. This method meets the objectives of matching field production observations. Also, a method is presented to quickly initialize a full field model using a 1-D compositional simulator to give full field model stability in an environment of high temperature gradient.
The final result is a 7 pseudo-component EOS with a single characterization defining the compositional gradient of the hydrocarbon column from gas to black oil. The method demonstrates that composition relative to depth can be predicted in those parts of the reservoir where samples do not exist, but where production and test data must be matched.
Other areas in northern Monagas state have similarly complex systems1. Many areas are only partially developed and can benefit by applying techniques presented in this paper to describe the fluids and to estimate gas-oil contacts.
Results of compositional simulation show a single EOS and vertical compositional variation reproduce the complex character of the field hydrocarbon column, matching field measured observations of saturation pressure (ps), gas-oil-ratio (GOR) and fluid densities.
Baseline Characterization of U.S. Exploration and Production Wastes and Waste Management
Authors: Petrusak R. L. , Freeman B. D. , Smith G. E. 
Published: December 2007

Abstract
The American Petroleum Institute (API) conducted a survey of onshore oil and gas exploration and production (E&P) operations and natural gas processing plant operations. The survey sought data for 1995 on current drilling practices, drilling and production waste volumes, and current practices for the management of wastes and produced water. API's survey was designed to update a similar survey of E&P waste management conducted a decade earlier. This paper presents the findings of the survey and compares the 1995 and 1985 survey results for the three main categories of oil and gas E&P wastes: Produced water – water brought to the surface with oil and natural gas,Drilling waste – rock cuttings, drilling mud, and other fluids produced as result of drilling a new wellbore,Associated wastes – various small volume wastes that include all other wastes "associated" with oil and natural gas production.
Between 1985 and 1995, the total volume of wastes generated annually by the oil and gas industry decreased by over 15 percent from 21.3 billion barrels in 1985 to 18.1 billion barrels in 1995. The decreased volume of E&P wastes generated is consistent with the general decline in E&P activity (lower oil production, fewer producing wells, fewer new wells drilled) which impacts the two largest volume waste streams -produced water and drilling waste. The survey results also demonstrate increased use of improved drilling and waste management practices during the past decade. For example, the results suggest a trend towards overall reduction of oily associated wastes, glycol dehydration wastes, and drilling wastes from operations using oil based mud. A significant, and growing, percentage of all E&P wastes (over 90 percent) are disposed of by injection.
Technologies and Possibilities for Larger-Scale CO2 Separation and Underground Storage
Authors: Holt T. , Lindeberg E. G. B. , Taber J. J. 
Published: December 2007

Abstract
International agreements on the need to reduce the emissions of greenhouse gases into the atmosphere may bring forward geo-storage of CO2. Several technologies are suited to recover CO2 from power production and industrial point sources. These emissions represent significant parts of the CO2 emissions in industrialized regions. Separation of CO2 from power plant flue gases, compression, pipeline transport and deposition will increase the electricity cost by approximately 50%, but the use of CO2 to recover additional oil may offer a significant value for large quantities of CO2. Underground storage in petroleum reservoirs and aquifers has a large capacity and is environmentally safe. On a long term the deposition capacity in oil reservoirs is limited, but at present, petroleum reservoirs represent significant sinks for CO2.
Underground storage of CO2 both in petroleum reservoirs and aquifers offers new business opportunities for the petroleum industry. The petroleum industry has a long time experience with all the operations and aspects involved with transport and injection of CO2 and other fluids into underground formations.
Fracture Fluid Damage to High-Permeability Gas Reservoirs: It Can Make A Difference
Authors: Robinson Bradley M. , Diyashev Iscander R. , Rahim Zillur , Wolhart Stephen L. , Salehi Iraj A. 
Published: December 2007

AbstractA new study has been performed that focuses on the reduction in gas flow rates and production that can occur due to damage from fracture fluid leakoff in high permeability gas reservoirs. We found, in some cases, fluid damage to the formation during fracturing operations (i.e., Frac Packs) may be more severe than what has been previously assumed in prior studies. As a result, gas flow rates can be significantly reduced, especially in gas reservoirs with moderate levels of permeability; e.g., 10 – 50 md. The results of the study also showed that some fracture treatments are not achieving sufficient propped lengths to overcome near wellbore damage, thus compounding the problem and further reducing gas flow rates
Supercritical CO2 Extraction Applied to Oily Drilling Cuttings
Authors: Saintpere Stephane , Morillon-Jeanmaire Anne 
Published: December 2007

Abstract
With environmental concerns playing a growing role in the drilling industry, drilling waste disposal has become on unavoidable and important component of a drilling team’s scope of work.
By end of year 2000, sea disposal of OPF (Organic Phase Fluid) will be phased out from the British North Sea area. Cutting Re-Injection or Ship-to-Shore for thermal, solvent or inerting treatments will be the only acceptable alternatives for oily cuttings disposal.
The following paper presents an innovative approach to the complex problem of the separation of OBM from cuttings using Supercritical Carbon Dioxide technology (SCCO2). Above 73,8 bars and 35°C, Carbon Dioxide (CO2) exhibits special properties such as high density, high diffusivity and low viscosity, but above all, tremendous solvent properties regarding non-polar molecules such as hydrocarbons. This special state, sometimes referred to as the 4th state of matter, is widely known as the supercritical state. CO2 in supercritical conditions is already widely used in various industrial extraction processes, such as coffee bean decaffeination, fragrances and flavors selection or pharmaceutical molecules production.
A pilot unit capable of handling up to 500g of cuttings per batch and allowing supercritical CO2 steady circulation, has been developed to study the efficiency of the process. Tests have been performed on oily cuttings coming from various locations and different OBM Cuttings. Best extraction conditions have been optimized and the efficiency of the separation has been very encouraging: Residual Oil Contents (ROC), as low as 0.2 % (by weight of dry cuttings) have been achieved.
An evaluation on 2 larger scale units has also been made: a 6 kg static reactor and a 10 kg rotating autoclave (both dedicated to pre-industrial feasibility studies) enabled the evaluation of the efficiency of the treatment on North Sea OBM Cuttings. Residual oil contents below 1% have also been reached proving that scaling up the process, from hundreds of grams to several kilograms, is viable and practicable.
The industrial potential of this promising technology is currently under study. The application of such a technology could constitute a major breakthrough in the drilling industry, both onshore and offshore.