bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pollut-Eval: An Innovative Tool for Direct Hydrocarbon Characterization in Oil Base Mud & Cuttings
Authors: Benoit Yves , Dalmazzone Christine , Audibert-Hayet Annie 
Published: December 2007

Abstract
Throughout the world, the drilling process generates a huge variety of contaminated solid waste. The environmental impact of these side products depends on their composition and concentration but also on the employed drilling technologies, based on water base mud (WBM) or oil base mud (OBM).
The various local and international Guidelines will gradually ban the discharge into the sea of these contaminated drilling waste.
The OSPAR 2000/3 decisions will soon prohibit their disposal into the sea and will recommend a "zero %" discharge of organic based drilling fluids.
With the emphasis placed on environmental safety, the oil companies are developing economical methodologies to clean oil contaminated field waste, such as cuttings or used drilling muds. One of the major challenge is to develop sensitive analytical tool to measure in a short time low oil content in a great variety of mineral matrix without major interference.
In this framework, this paper provides answers concerning the problem of quantification of low oil content in complex solid waste. A study has been performed to demonstrate the ability of the Pollut-Eval method to characterize and quantify hydrocarbon contamination without any pretreatment. In a first step, analytical results of pure hydrocarbon cuts commonly used in drilling muds (iso and n-paraffin, α olefin, ester and diesel cuts) will be presented to demonstrate the qualitative and quantitative efficiency of the method.
In a second step, evaluation of the total organic content of various drilling muds will be compared to their hydrocarbon concentration to demonstrate that no major interference occurred in the characterization or quantification of these petroleum cuts despite the various and complex mud formulations. In a last step, Pollut-Eval residual oil content (ROC) and total organic carbon (TOC) of undersea discharged cuttings sampled at 200 m depth (more or less distant from an offshore rig) will be presented and compared to capillary gas phase chromatography results.
As a conclusion, Pollut-eval performance will be discussed and compared to other methods commonly used in oil industry: global carbon organic determination by catalytic oxidation and retort kit distillation.
Standoff Compensation and Hole Size Correction of a New LWD Density/Neutron Logging System
Authors: Mickael M. , Jones D. , Phelps D. 
Published: December 2007

Abstract
A new LWD porosity logging system has been developed that addresses specific issues related to the repeatability and accuracy of porosity measurements while drilling. This system provides density and neutron porosity measurements at penetration rates up to 400 ft/hr with the precision and accuracy of an equivalent wireline tool. Designed to operate in the offshore deepwater and ultra-deepwater environment, system specifications include operating pressures up to 30,000 psi. The system is designed to reduce standoff effects on the density measurement and correct the neutron and density measurements for the effects of standoff and borehole size while drilling.
Standoff compensation of the density measurement is achieved using a new technique called "Self Binning". This technique relies on measurements made by the density tool itself to correct for tool standoff. The count rate of the near detector is sampled at a very high rate and combined in such a way as to divide the borehole into segments of fairly constant standoff. A standoff correction is applied to each segment and an average corrected density is calculated after removing data with excessive standoff.
A similar technique is used to segment the borehole according to formation density. The corrected densities sampled at a high rate are sorted according to formation density to provide a continuous profile of the azimuthal formation density around the borehole circumference.
Additionally, estimates of tool standoff and borehole diameter are determined while the tool is rotating. This information is applied to the neutron measurement to obtain a neutron porosity measurement corrected for borehole and standoff effects.
Details of these new algorithms as well as modeling and experimental data used to optimize and test these algorithms are presented. Examples are presented that show the accuracy and repeatability of the new toolstring.
LWD Sonic Logging in Large Diameter Surface Holes
Authors: Market J. , Hauser M. R. , Althoff G. , Deady R. J. , Varsamis G. L. 
Published: December 2007

Abstract
Sonic logging in large diameter surface holes in offshore environments such as the Gulf of Mexico has traditionally been problematic from both operational and economic perspectives. Acquisition of high-quality wireline sonic log data in large diameter, shallow holes is often compromised by borehole enlargement or washout that may occur before wireline tools are run, and by the typically high signal attenuation encountered in shallow formations and large boreholes. Even if adequate quality wireline sonic data can be obtained, the rig time and cost required for the wireline run may be as great as that required for the actual drilling of the surface hole. However, sonic velocity data in these shallower intervals can be particularly important to geophysicists for use in seismic velocity modeling or time-depth correlation. Sonic log data can also be used for formation evaluation and for drilling applications such as pore pressure determination.
To improve sonic data acquisition while eliminating rig time and costs associated with wireline logging, a 9 ½" diameter LWD sonic tool has been developed particularly for these logging environments. The tool is designed with two opposed transmitters capable of firing strong signals at multiple frequencies, and dual, seven-element receiver arrays for a high signal/noise ratio in the soft, highly-attenuating formations. The tool is mechanically compatible with larger BHA's used to drill large-diameter surface holes, while providing high-quality compressional slowness (Δtc) logs in boreholes ranging from 14 ¾" to 26" in diameter. Centralization is not required, and the tool is compatible with bi-centered bits; thus, it can also be used to provide porosity and pore pressure information in applications where bi-centered bits preclude the acquisition of high-quality LWD neutron porosity and density data. The sensor is combinable with 9½" directional, gamma ray, resistivity, and annular pressure sensors to facilitate both drilling and formation evaluation applications in real time in large boreholes. Along with the design and modeling of the 9-1/2" sonic tool, example data are presented from large surface holes (17 ½" to 26") in the Gulf of Mexico.
Engineering Calculations of Gas Condensate Well Productivity
Authors: Mott Robert 
Published: December 2007

Abstract
The productivity of many gas condensate wells is reduced by the formation of a condensate bank in the near-well region. Forecasting of gas condensate well productivity usually requires fine-grid numerical simulation to model the formation of the condensate bank, and to account for high-velocity phenomena such as non-Darcy flow and changes in relative permeability at large capillary numbers.
This paper presents a new technique for forecasting performance of gas condensate wells, using simpler techniques, which can be used in a spreadsheet. The calculation uses a material balance model for reservoir depletion and a two-phase pseudopressure integral for well inflow performance. The pseudopressure integral technique has been extended to include high-velocity effects and also to allow for the change in produced fluid composition due to the formation of the condensate bank.
The new technique has been tested by comparison with the results of fine-grid compositional simulation, and the results are in good agreement for a wide range of cases covering vertical, horizontal and hydraulically fractured wells.
The spreadsheet model provides a useful tool for rapid forecasts of condensate well performance, for examining the effects of condensate blockage in different well types or for studying sensitivities. It is also valuable where simple models of condensate reservoir performance are required for use in integrated studies involving issues such as surface facilities, drilling schedules and gas sales contracts.
Case Studies Using Reservoir Characterization To Improve Remediation System Design and Operation
Authors: Bust Vivian K. 
Published: December 2007

Abstract
Improved remediation design and operation resulted from effectively using reservoir-aquifer characterization tools to identify hydraulic flow units and connectivity of sediments in contaminant-affected shallow aquifer-aquitard systems. The objective of this approach was to utilize an improved understanding of subsurface conditions to develop more effective remediation designs and operating plans. This was accomplished by developing an increased understanding of aquifer storage and flow properties, preparing geologic models, and identifying contaminant migration pathways and permeability barriers. Characterization methods practiced in petroleum exploration and production were applied to near-surface sedimentary sequences to describe the subsurface hydrogeologic setting. Stratigraphic analysis using continuous core, detailed core descriptions and analogous sedimentary environments of deposition was employed to develop deterministic geologic models of the subsurface. Predictive mapping was used to delineate contaminant-affected soil and groundwater, and interpretations were adjusted in an iterative manner with the acquisition of data.
This paper will discuss case histories of overall project characterization and remediation of two sites located in Southern California, USA. These case studies demonstrate the effect of subsurface soil heterogeneities and variation in contaminant distribution on remediation.
The Value of Flexibility in Managing Uncertainty in Oil and Gas Investments
Authors: Begg Steve , Bratvold Reidar , Campbell John 
Published: December 2007

AbstractThis paper deals with improving the oil and gas industry's ability to manage the impacts of uncertainty on investment evaluations. We first review the economic performance of the industry and conclude that it is not good. Under-performance is attributed largely to poor investment decision-making, which is in turn due to inaccurate evaluation of the economic impacts of uncertainty. We describe how undue focus on Value of Information (VoI) and classical DCF techniques can prevent full value creation from an investment opportunity, by not encouraging exploration of the use of flexibility to manage, or even exploit, uncertainty. A Real Options (RO) approach has considerable appeal in overcoming this problem. However, its widespread application has yet to occur due to unfamiliarity, issues around its robust implementation and a focus on valuation rather than value creation.Here, the VoI concept is extended to assessing the Value of Flexibility (VoF). Building on a previously published framework (SPE 71414), we show how VoI and VoF analyses can be performed using a Stochastic Integrated Asset Model and thus offer a practical means to capture some of the benefits of a real options approach. The VoI concept is reviewed and illustrated by the example of executing a seismic study to reduce OOIP uncertainty. VoF is illustrated by planning extra slots on a platform to manage residual OOIP uncertainty and by estimating the value of incremental water injection facilities to manage uncertainty in aquifer strength. Value creation from flexibility is illustrated by considering the potential to change production rate as oil price changes.
Quantification of Petrophysical Uncertainty and Its Effect on In-Place Volume Estimates: Numerous Challenges and Some Solutions
Authors: Fylling Arne 
Published: December 2007

AbstractThe subject of this paper is the quantification of uncertainty in the petrophysical variables porosity, water saturation and net to gross ratio as estimated in wells, and the significance of such uncertainty for in-place volume estimates. If the nature of petrophysical uncertainty is not properly accounted for in this process, directly misleading uncertainty estimates may be derived. This can be the case if one or more of the following issues are disregarded:Firstly, the petrophysical variables are not independent. This can be taken into account by replacing the individual petrophysical variables with the variable Hydrocarbon Pore Fraction, HCPF, in the uncertainty estimation. This variable is the hydrocarbon fraction of the gross rock volume, and uncertainty in this variable can conveniently be combined with uncertainty in gross rock volume to derive the uncertainty in hydrocarbon pore volume (HCPV)Secondly, randomly distributed errors in petrophysical variables are usually insignificant for in-place volume uncertainty, due to averaging of large data volumes. Systematic errors are not removed by averaging, and a key issue is the estimation of such errors, which cannot be done by applying statistical procedures to the data. The effect of such errors on HCPV uncertainty is critically dependent on the degree of correlation between errors in different wells and zones.Thirdly, the errors caused by the combined effect of reservoir properties, differences and limitations in logging tool response functions and the choice of evaluation model and parameters are a major source of uncertainty in any reservoir with some degree of heterogeneity. Therefore, estimating the uncertainty at the log depth increment level by more or less rigorous and comprehensive error propagation or Monte Carlo methods based on log, core measurement, evaluation model and parameter uncertainty only, is insufficient.The systematic nature of the petrophysical uncertainty in wells will cause general HCPV level uncertainty. The uncertainty relating to mapping of properties between wells is an issue by itself. However, in many cases uncertainty related to water saturation mapping functions can be conveniently linked with uncertainty in HCPF in the wells, and quantified by simple spreadsheet methods as part of the petrophysical uncertainty estimation. The methods and algorithms for doing so are also given in this paper.
Implementing Intelligent Well Completion in Brown Field Development
Authors: Johnstone Stuart , Duncan Gavin , Giuliani Corrado , Denholm Allan 
Published: December 2007

Abstract
Intelligent Well Completions (IWC) is an emerging technology, which allows operators to optimise reservoir management and field facilities performance. The implementation of this technology has generally been restricted to new field development due to the perceived complexity of integrating high-end IWC (combined monitoring and flow control) into current Subsea Production System (SPS) designs. However, intelligent completions can be applied to mature fields where reservoir performance and value added by IWC are well understood. The BP Machar well application is a typical example.
One of the challenges facing the project team was the integration of the IWC control system within the constraints of the existing SPS. Minimum modification to the existing hardware and control system equipment was a requirement.
A system approach, similar to the forthcoming ISO standard for integration of IWC into Subsea Production Systems, was used to ensure robustness of the design and testing concepts.
Prudhoe Bay Oil Production Optimization: Using Virtual intelligence Techniques, Stage One: Neural Model Building
Authors: Mohaghegh Shahab D. , Hutchins Lynda A. , Sisk Carl D. 
Published: December 2007

Abstract
Field data from the Prudhoe Bay oil field in Alaska was used to develop a neural network model of the cross-country gas transit pipeline network between the production separation facilities and central gas compression plant. The trained model was extensively tested and verified using 30% of the data that was not used during the training process. The results show good accuracy in reproducing the actual rates and pressures at the separation facilities and at the gas compression plant. The correlation coefficient for rate and pressure were 0.997 and 0.998 respectively.
This is the first phase in the development of a tool to maximize total field oil production by optimizing the gas discharge rates and pressures at the separation facilities. The second phase, development of a state-of-the-art genetic algorithm to perform the optimization, is currently being tested and will be the subject of a future paper.
The Potential for State-of-the-Art Decision and Risk Analysis to Contribute to Strategies for Portfolio Management
Authors: Simpson G. S. 
Published: December 2007

Abstract
The titles of papers given at industry conferences over the last couple of years suggest a significant rise in the level of awareness of the potential for decision and risk analysis (D&RA) techniques to impact portfolio-related decisions, from exploration acreage acquisition through drilling and development decisions to transportation and downstream issues.
This may well be a function of the increase in the number and complexity of upstream partnerships and alliances and that, combined with a tightening of money markets, leads to greater difficulties in reaching agreement on portfolio-related decisions.
These portfolio management decisions include those that relate to: –which assets should be in, or out of, the portfolio?–what are the appropriate equity levels in each asset?–when is the best time to start, or continue, investing in each asset?
The increase in interest might also be a result of competitive pressures: if some companies are seen to be using techniques which appear or promise to give them a competitive advantage – smarter decisions leading to more efficient portfolios – then other companies will quickly feel the need to do the same.
This paper presents a model for portfolio management strategy formulation which starts with the application of the latest D&RA tool developments to individual asset value assessments, continues through the generation and analysis of potential portfolios, and ends with the incorporation of the insights thus generated into a strategy formulation and implementation stage.
The paper argues that the ultimate objective of D&RA is to optimize a company's portfolio of assets, that the use of sophisticated D&RA tools is a critical foundation necessary for achieving that objective, and that the industry still has some work to do before some potentially very important techniques, such as real options valuation, are practical working tools which everyone can and should use.
Proving It – A Review of 80 Published Field Studies Demonstrating the Importance of Increased Fracture Conductivity
Authors: Vincent M. C. 
Published: December 2007

AbstractMany engineers disregard laboratory reports demonstrating that the pressure losses across proppant samples are substantial. Similarly, it appears that the modeling studies warning of substantial productivity losses due to inadequate fracture conductivity have not been universally convincing.Perhaps many practical frac engineers simply object to the theoretical nature of these arguments, when they quote one of the more influential orators of our time, Shania Twain,1 stating, "That don't impress me much."Instead, many Petroleum Engineers prefer to see the economic benefit demonstrated in real reservoirs, and seemingly borrow a quotation from the film Jerry Maguire,2 stating, "Show me the money!"The purpose of this paper is to summarize the results of over 80 field studies where well productivity was improved by increasing the fracture conductivity. The benefit of increased conductivity has been demonstrated in oil, condensate, and gas reservoirs in 50 regions around the globe. This benefit was documented by 250 authors representing over 70 companies. Increased conductivity has been shown to be beneficial in oil wells producing 2 bopd to 25,000 bopd, and in gas wells producing less than 1 MMCFD to over 100 MMCFD. Higher conductivity fractures were proven to improve the cash flow in carbonates and sandstones at depths of 2800 to 20,000 feet, and in low rate coal bed methane wells shallower than 1500 feet.This review of industry experiences in a wide variety of reservoirs is not presented as a substitute for a comprehensive optimization study in a specific location. Instead, the following summary demonstrates that well productivity and profitability can frequently be improved with redesign of hydraulic fractures, despite the failure of many existing production models to predict those benefits.These studies are presented to satisfy the following goals: 1)To verify that the extreme pressure losses observed in the laboratory and predicted by current fluid flow theory are real, i.e., "Proving It".2)To provide a list of fields, encompassing a wide variety of reservoir types, to assist engineers searching for results from an analogous field.3)To provide a number of field studies to which production models can be calibrated.4)To summarize the collective experience of over 250 authors, and incorporate what they have learned into future fracture designs.5)To demonstrate the relationship between fracture conductivity, well productivity, and cash flow, i.e., "Show me the money!"
Effect of Composition on Waterblocking for Multicomponent Gasfloods
Authors: Bijeljic Branko R. , Muggeridge Ann H. , Blunt Martin J. 
Published: December 2007

Abstract
During tertiary miscible gas injection direct contact between gas and oil can be prevented by water surrounding residual oil. The principal aim of our study is to assess the importance of this waterblocking phenomenon in multicomponent gas injection. We study this process using a multicomponent pore-scale model. Light components in the gas dissolve in the water and diffuse through the water to reach the oil. This causes the oil to swell. Eventually the oil swells sufficiently to contact the gas directly. However, components in the oil can diffuse into the gas, causing the oil to shrink and preventing the contact.
We apply our model to a variety of first-contact and multiple-contact miscible gas/oil systems from published field studies. Due to the low solubility of hydrocarbons in water, oil swelling and shrinkage can prevent direct contact for many days to years. We show that increasing the miscibility of injected gas, by, for instance, moving from a multi-contact miscible to a first-contact miscible displacement increases the time taken to achieve direct gas/oil contact. This leads to an extended two-phase region in the reservoir, even for a thermodynamically miscible gas flood.