bluuebunny/crossref_metadata_2025_split huggingface dataset:
Three Statistical Pitfalls of Phi-K Transforms
Authors: Delfiner P. 
Published: December 2007

Abstract
Phi / k transforms are widely used to predict permeability. Some of the difficulties of this exercise are well identified, such as the homogeneity of the population (rock typing), the matching of cores and logs (especially depth matching), and the problem of permeability upscaling. Not so well known, however, are the pitfalls of a statistical and geostatistical nature that may create significant biases, always in the same direction, an underestimation of permeability.
The passage from Phi to k is performed in three steps:
(1) in cored wells, an exponential regression equation is established between core porosity and core permeability k; (2) in uncored wells, log porosity is used instead as input; (3) the same equation is sometimes used again to populate the cells of a dynamic reservoir model in 3D, where input porosity values are obtained by interpolation.
The core-scale regression equation generally underestimates permeability by at least a factor of 2. The origin of the bias lies in the reverse transformation from logarithmic to arithmetic scale. To avoid this pitfall a new permeability estimator is proposed, based on the quantile curves of the Phi / k crossplot. This estimator is data-driven and does not a priori assume any particular functional relationship between Phi and k, such as an exponential regression function.
One of the simplest diagnostic tools to check the agreement between log and core porosity is a crossplot of one against the other. In the absence of bias the points are expected to be distributed along the Y = X line. In reality they are or they are not, according to which variable is plotted along the X axis. This apparent paradox is elucidated by bivariate regression theory and related to the difference of investigated volume between core and log data.
Direct input of upscaled cell porosity into an exponential core-scale permeability transform amounts to forcing geometric permeability averaging, which may again lead to serious underestimation of the true upscaled permeability when heterogeneity is significant.
Fault Leakage Potential Analysis in the Cantarell Field, Mexico, Using Geomechanics
Authors: Celis E. , García-Hernández J. , Morales-Ramírez J. M. , Cabrera-Toledo C. , Sheridan J. , Ward C. , Wiprut D. 
Published: December 2007

Abstract
Petróleos Mexicanos (PEMEX E&P) and GeoMechanics International Inc. (GMI) worked together to define the potential for fault leakage in the Sihil and Frontal faults of the Cantarell and Sihil Fields, Mexico. Water production with a low salinity content in the northern area of the Akal block in the Field seems to be derived from neighboring blocks of Tertiary age and not from the water leg of the reservoir. Pore pressures in the reservoirs from the Akal block have depleted significantly since production started in the late seventies. Nitrogen injection started in the late nineties and has contributed to pressure maintenance since then. Overpressures in the shale layers above the reservoirs have been identified. A number of studies have shown that shear failure along reservoir-bounding faults can increase fault permeability and compromise fault trap integrity. The orientation of a fault and the magnitudes of the present-day stresses and pore pressure acting on the fault will determine whether the fault has the potential for shear failure and therefore a potential for leaking. The analysis of fault leakage potential was based on a geomechanical model covering the northern area of the Cantarell Field and its changes with time due to reservoir depletion and nitrogen injection. Information from wireline logs, downhole tests and drilling events from eight wells drilled between 1979 and 2005 were used to build the geomechanical models that change with time. The principal effective stress model (the magnitudes and orientation of the principal stresses), and the mechanical properties model were defined and validated with image logs, caliper logs and drilling experiences before their use for fault leakage potential analysis. Specific sectors of the two faults appear to be tectonically active during the production history and therefore had potential to leak. Fault leakage potential may explain water production with low salinity content in the northern area of the Akal Block in the Cantarell field.
Streaming Potential Applications in Oil Fields
Authors: Chen M.-Y. , Raghuraman B. , Bryant I. , Supp M. 
Published: December 2007

Abstract
Two successful field tests of streaming potential measurements in oil fields have been carried out: one in a horizontal oil production well and one in a vertical water injection well. Pressure transients were created and the streaming potentials generated by these transients were measured by arrays of permanent electrodes placed in the boreholes. The electrodes are partially insulated from the other completion components but nonetheless record high signal-to-noise ratio responses. These field experiments have demonstrated that the streaming potentials arising from pressure transients can be measured accurately under borehole conditions. Numerical methods have been developed to interpret these measurements to offer distributed characterization of matrix permeability at various depths of investigation and effective fracture transmissibility.
While streaming potentials have been observed in many laboratory rock experiments, we believe these are the first streaming potential transients to be measured in an oil field. The field experiment results, together with forward and inverse modeling studies, indicate many possible applications of transient streaming potentials in oil and gas fields for reservoir characterization and reservoir monitoring.
Planning and Identifying Best Technologies for ERD Wells
Authors: Gupta Adit 
Published: December 2007

Abstract
This paper on ERD wells focuses on nearly all important aspects of drilling ERD wells. Various case studies have also been taken while discussing various aspects so as to signify the practical experience of ERD wells. The latest technology for drilling ERD wells has been taken up. This paper will discuss the planning of ERD wells, the latest technology for ERD wells, the consideration of drill pipes and drilling fluid design for ERD wells, completion of ERD wells, well control and fishing and workover tools for ERD wells.
At the end, suggestions have been given so as to get better results for ERD wells.
Time-Dependent Behavior of Drilling Fluids Under Cyclic Temperature and Pressure Loads
Authors: Piber M. , Prohaska M. , Hublik G. , Thonhauser G. 
Published: December 2007

Abstract
Drilling fluids are subjected to cyclic pressure and temperature loads when circulated in the wellbore. However, little information exists about quantitative changes of fluid viscosities during long-term circulation. Therefore the effects of temperature/ pressure cycles on viscosity reduction/ regaining for different Xanthan products - dissolved in pure solutions and in drilling mud - and for Bentonite fluids are evaluated in a laboratory study. To model these cyclic temperature/pressure loads a new HPHT cyclic load test has been developed and the impact of temperature and time dependent viscosity on hydraulics calculations is evaluated quantitatively.
First, the ability of Xanthan and Bentonite fluids to break and reestablish viscosity under cyclic temperature and pressure loads was evaluated. Furthermore it was investigated whether fluids are able to build up original viscosity after applying cyclic temperature and pressure loads. This effect is defined as viscosity degradation per load cycle which could be quantified as part of this work. Bentonite, in contrast to Xanthan fluids, however has a different, more complex and stronger time and temperature dependent viscosity behavior when cyclic loads are applied. For the investigated fluids a significant impact of time dependent behavior under cyclic temperature and pressure loads on hydraulics modeling is shown.
By performing the new test procedures it is possible to quantitatively determine cyclic viscosity degradation. When using these findings, the accuracy of hydraulic modeling and nozzle optimization can be improved. Better predictions of critical viscosity breakdowns and additive requirements to maintain fluid viscosity can be done.
Hydrocarbon Production Forecast and Uncertainty Quantification: A Field Application
Authors: Rotondi M. , Nicotra G. , Godi A. , Contento F. M. , Blunt M. J. , Christie M. A. 
Published: December 2007

AbstractRealistic reservoir models are essential for efficient field management and accurate forecasting of hydrocarbon production. Such models, based on the physical description of the reservoir, need to be calibrated or conditioned to historical production data. The process of incorporating dynamic data in the generation of reservoir models, known as history matching, is traditionally done by hand and is a very tedious, time-consuming procedure that, in addition, returns only one single matched model. It has been shown that the best matched model may well not be a good predictor of future performance.In this work, one of the first field applications of the Neighbourhood Algorithm (NA) is presented. The NA is a stochastic sampling algorithm that explores the parameter space, finds an acceptable ensemble of data fitting models and extracts robust information from this ensemble in a Bayesian framework. The aim is to forecast hydrocarbon production accurately and to assess the related uncertainty by means of multiple reservoir models.The NA methodology was extensively applied to an offshore gas field and compared to a previously manually matched model. The Mistral field has been producing for 6 years from 7 wells. Gas and water productions and pressure data were available and the uncertainty quantification was consistently obtained. Algorithm control parameters and objective function definition effects were investigated. The posterior probability density functions of each unknown parameter, calculated taking into account the observed production data, were evaluated. The hydrocarbon production was forecast using Bayesian inference and the economic risk estimated. The overall process was carried out with a significant time reduction compared with the previous manual approach.The results presented suggest that use of stochastic sampling techniques in a Bayesian framework may well be a valid alternative methodology to the traditional industry workflow for the uncertainty quantification in producing fields.
Successful Application of Glass Reinforced Epoxy (GRE) Casing in Hydraulically Fractured Water-Injection Wells
Authors: Peralta D. , Maggioni A. , Garcia R. , Martin D. 
Published: December 2007

Abstract
This paper describes the successful application of Glass Reinforced Epoxy (GRE) casing in 1,100-m water injection wells in Puesto Hernandez field, Argentina.
Prior to running 5 1/2-in. casing, thorough testing was carried out to evaluate the actual performance during frac treatments using a surface-mounted model. Other tests were designed and carried out to evaluate casing behavior during running, cementing and perforating operations.
Operational aspects, such as the effect of buoyancy, cement logging and downhole tools are addressed, as well as solutions and proposed approaches to remaining problems.
To date, four wells have been completed with this technique. Results indicate that casing, tools and operational techniques are appropriate and represent an innovative, sound alternative to reduce maintenance costs associated with scaling and corrosion.
Technology Implementation to Enhance Reserves Recovery in Mature Fields Requires a New Business Model Between Service Companies and Operators
Authors: Ross D. A. , Kalfayan L. , Smith K. 
Published: December 2007

Abstract
According to worldwide hydrocarbon production statistics, mature fields produce approximately 70 percent of global production. Average recovery rate from these mature fields worldwide is only 35 to 37 percent. The rate is even lower in the U.S.: Of the 609 billion barrels of original oil in place estimated by the U.S. Department of Energy (DOE), 351 billion barrels is thought to be unrecoverable by existing technology. To meet the ever-increasing demand in worldwide hydrocarbon production and avoid energy crisis situations, the oil and gas industry needs to substantially increase recovery factors associated with mature fields.
Current business models among operators and service providers have greatly restricted the ability to implement traditional and emerging technologies required to enhance the performance and extend the life of mature fields. During the past decade, the industry has increasingly depended on service providers to develop new technology. Meanwhile, service providers must recoup technology development investments in a relatively short period because of the short-term economic objectives and expectations dictated by the investment community.
New oil and gas fields have different economic drivers than mature fields; new field economics often justify the use of new technologies and field-wide engineering projects to maximize production and profit, whereas mature field economics (and current business models) limit technology implementation and focus on single-well solutions.
To complicate matters further, both operators and service providers often lack personnel resources to strategically implement full-scale field management programs with the objective of optimizing recovery efficiency. Frequently, one-off remedial treatments are performed without a proper field-wide objective in mind.
A new approach can ensure better use of technology in exploiting mature fields. This approach between service provider and operator incorporates a strategy to restructure the service cost basis and better balance risk and reward associated with technology utilization.
Development and Commercial Deployment of an Expandable Monobore Liner Extension
Authors: Stockmeyer C. F. , Tillman D. L. , Weirich J. B. , Sehnal Z. 
Published: December 2007

Abstract
For a number of years, the exploration and production industry has sought to prove the feasibility of monobore expandable liner extensions as an advantageous alternative to conventional casing designs. Included as part of the initial casing design, the goal of an expandable monobore liner extension is to enable the operator to drill deeper exploration and production wells with larger hole sizes at the reservoir. As a contingency plan, the goal is to enable the operator to isolate zones that contain reactive shales, sub-salt environments, low fracture gradient formations or other drilling situations without having to reduce the casing and subsequent drilled hole size into the reservoir. A one-trip, top-down expansion system was developed and tested to prove the feasibility of the expandable monobore liner extension concept, including the ability to provide an optimized, cost-effective casing configuration without reducing drilled hole size. During the development process, the need for expandable open-hole packers or optional cementation of the liner was identified and addressed. This paper details the development process for the expandable monobore liner extension system, including testing and the resulting commercial field deployment in an operator well to qualify the technology.
This paper will demonstrate the challenges faced during various planning and execution stages and explain how those challenges were met, specifically in the following areas:
Pre-planning wellbore design options and considerations Monobore liner extension selection, one-trip system reliability System qualification Zonal isolation requirements Field installation considerations Expansion process Safety and environmental impact Post deployment results
Characterisation and Modelling of a Fractured Reservoir Using a Novel DFN Approach
Authors: Gouth F. , Toublanc A. , Mresah M. 
Published: December 2007

Abstract
Characterising and modelling of naturally fractured reservoirs (NFR) with fracturing at different scales is usually a challenging task as the specific response from each scale is difficult to isolate.
We focus on a carbonate reservoir in North Africa, in production for two years. There is evidence of fracturing at different scales (from diffuse fractures to conductive faults) with significant implications for oil production.
We first present the way fractures have been fully characterised using an extensive integration of static (FMI) and dynamic (Well test, Pressure Build Up, Mud losses) data. The advanced use of well test signatures in understanding the main flow mechanisms occurring within the reservoir is emphasized.
Then, we detail the way the dynamic model was build using a novel discrete fracture network (DFN) approach developed internally. The method populates the static parameters at the full field scale using a geo-statistical process guided by a geological driver. Using an innovative technique (the Elementary Patch), a fast calculation of fracture permeability in each grid cell and automatic calibration on the well test data can be made. We also discuss how the best choice for the simulation model (single porosity vs double porosity) depends not only on the fracture-to-matrix permeability ratio but also on the magnitude of the shape factor and on the production mechanism. The final dual porosity–dual permeability model integrates the intermediate scale fractures implicitly and the conductive faults explicitly whereas the smallest scale is discarded as it has a negligible impact.
In summary, we present a complete and innovative workflow process for a geoscience study on NFR and demonstrate its application in a real case study. The need for full data integration to achieve a comprehensive understanding of the flow mechanisms involved during production is underlined.
Polymer Powder/Cement Composites
Authors: Chougnet A. , Audibert A. , Lecolier E. , Moan M. , Guichard B. , Mazard C. , Valenti A. 
Published: December 2007

Abstract
The selection of an optimal cementitious material is critical to maintain zonal isolation for the lifetime of oil and gas wells not only for primary cementing but also for well abandonment. Polymer powder/cement composites present good mechanical and durability properties since polymer latex promotes improved adhesion and flexibility to the hardened cement paste. So, for oilwell applications, which require high durability under aggressive environment, polymer powder/cement composites would be good candidates. During the well completion phase, the slurry placement strongly depends on its rheological behaviour that is studied here for polymer powder/cement composite suspensions: they present a shear-thinning behaviour in permanent shear and a transition from a gel to a liquid behaviour in oscillatory shear. The replacement of cement particles by polymer particles induces a decrease of the viscosity in the liquid state and of the storage modulus in the gel state. The good quality of the polymer particle dispersion and their high affinity for cement particles were observed by SEM and cryo-SEM. Solid state NMR (29 Si and27Al) and DSC help to understand the influence of the polymer addition on the hydration/hardening. Depending on the temperature and on polymer chemistry, it may strongly influence the hydration reactions of the materials and their kinetics. All these results help us to understand the relations between the slurry composition, its rheological behaviour and the properties of the hardened materials.
The Search for Alternatives to Screen: Is Permeable Cement a Viable Option?
Authors: Vidick B. , James S. , Drochon B. 
Published: December 2007

Abstract
The search for a cost-effective alternative to screens has been intensive in the sand control field. Different systems have been proposed in the past, including various solutions based on permeable cement, but none of them have made a real breakthrough.
This paper presents a new permeable cement system that has significant advantages over previous systems. In particular, this permeable cement was formed in a one-stage process, eliminating the need for a subsequent treatment to generate permeability. This permeable cement system also has adequate strength and sufficient permeability for several sand-control applications. However, the durability of the permeable cement was evaluated and found to be poor. Some suggestions are made for possible applications of the permeable cement.
Correcting Common Errors in Probabilistic Evaluations: Efficacy of Debiasing
Authors: Welsh M. B. , Begg S. H. , Bratvold R. B. 
Published: December 2007

Abstract
‘Debiasing" refers to techniques taught during risk and uncertainty training that enable trainees to avoid or reduce errors arising from cognitive biases. We discuss current techniques and their applicability to oil and gas decisions.
To test the debiasing efficacy of sitting a general decision making course, engineering students completed a survey [1] designed to test for the well-known overconfidence and anchoring [2] biases both immediately prior to and following a short course on the psychology of decision making containing sections on cognitive biases and debiasing. No feedback or specific training was included in the course, - which described debiasing techniques for various cognitive biases including those tested within the battery.
Participants' results on the overconfidence task showed a 21% improvement in calibration – from 27% to 48%, indicating a significant impact of knowing about biases and debiasing methods on susceptibility to overconfidence. However, no improvement was seen in participants' performance on the anchoring task.
The first result, taken in conjunction with findings from Welsh et al [1], suggests that training in dealing with uncertainty, and knowledge of the modes of action of cognitive biases, can reduce overconfidence but that this benefit is reduced as time since training increases. The second result, again in conjunction with previous findings [1, 3], suggests that training alone is insufficient to overcome the anchoring bias in isolation from domain specific knowledge. That is, to reduce the adverse effects of the anchoring bias, trainees need to be both trained in debiasing techniques and possess knowledge about the field in question such that they can apply the debiasing techniques to their knowledge.
We use these preliminary, experimental results to highlight and inform discussion regarding the potential benefits of debiasing. Specifically, we argue that the efficacy of debiasing within oil and gas decision making requires further research – in particular, a longitudinal study to track the efficacy of debiasing over time. We conclude that an understanding of the potential and limitations of training in debiasing techniques will allow management to formulate effective strategies for the introduction and maintenance of debiasing training to reduce the impact of errors arising from cognitive biases. Additionally, it is argued that introducing future industry personnel to these concepts during their university studies will ease their integration into industry practice