bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combination of Experimental Design and Joint Modeling Methods for Quantifying the Risk Associated With Deterministic and Stochastic Uncertainties - An Integrated Test Study
Authors: Manceau E. , Mezghani M. , Zabalza-Mezghani I. , Roggero F. 
Published: December 2007

Abstract
This paper presents a fully-integrated methodology for managing reservoir uncertainties during history matching, production forecasting and production scheme optimization.
Based on the traditional experimental design methodology, this innovative approach, called the Joint Modeling Method, allows to model the production recovery as a function of both the deterministic uncertain parameters, such as petrophysical and production parameters, as well as non-continuous parameters such as geostatistical realizations and equiprobable matched models. In this new approach, the dispersion due to the non-continuous uncertainties is modeled in a rigorous statistical framework through the variance of the production recovery.
The method was successfully applied on data derived from a North Sea real field case. The objective was to quantify the impact of the principle reservoir uncertainties on the cumulative oil production and to optimize future field development in a risk analysis approach. The uncertainties were mainly on petrophysical data, geostatistical facies distribution and aquifer strength. The study was performed in the following steps: –sensitivity study. The most influential parameters were identified and the impact of geostatistical uncertainties was highlighted.–history matching. The influential parameters were constrained to the available production data. In particular, the geostatistical model was locally modified using both FFTMA technique and the gradual deformation method.–production scheme optimization. Experimental design and joint modeling were used to obtain probabilistic distributions of the optimized location of new wells in a non-producing zone.–risk analysis: Finally, probabilistic incremental oil production was obtained using Monte-Carlo technique.
Results show that this integrated methodology successfully enables to quantify the risk associated with the main reservoir uncertainties during the whole process of a reservoir engineering study (sensitivity, history match, production optimization and forecast).
Layered Modulus Effects on Fracture Propagation, Proppant Placement, and Fracture Modeling
Authors: Smith M. B. , Bale A. B. , Britt L. K. , Klein H. H. , Siebrits E. , Dang X. 
Published: December 2007

Abstract
Hydraulic fracture geometry (i.e., critical results of length and proppant placement) is driven by four major in situ parameters: Fracture Height (H), Modulus (E), Fluid Loss (C), and "Apparent" Fracture Toughness (KIc–app). In many (even most) cases, "Height" is the most important of these parameters –due to the need for some height confinement to achieve long fractures, or the need for height growth to insure good pay coverage. Due to this importance, industry research effort and most field measuring techniques concentrate on "eight." In particular, the growing use of seismic imaging is offering a tool to measure height growth away from the wellbore. Results from such diagnostics have often shown, as one expects, that in situ stress variations control height. However, results have also shown situations where this is apparently not the case.
This paper examines another in situ parameter, "Layered Modulus," which also affects height. In addition, by controlling the "local" width of a fracture, layered modulus (i.e., layered formations with different layers having significantly different modulus) can have a critical effect on final proppant placement.
The importance of layered modulus in directly controlling fracture height is illustrated in this paper, and this is compared with published solutions. In general, it is found that, just as concluded in the past, modulus contrast is probably not an important parameter in terms of direct control of fracture height. The greater importance lies in the effects on local fracture width. These local width changes can have a significant influence on controlling proppant placement – and this can be critical for low net pressure cases such as "water fracs" or fracturing in "soft" formations. It is also noted that layered modulus significantly impacts the average width of a fracture, and thus impacts the critical material balance aspects of fracture modeling if not properly accounted for.
Finally, some of the theoretical solution problems created by "Layered Modulus" formations for fracture modeling are discussed and compared. This is done by comparing with 3-D Finite Element (static) solutions, and shows how some common industry "approximations" for layered modulus give incorrect results. Based on this, examples with a fracture propagation model using a finite element-generated stiffness matrix are used to define types of cases where a simple "average" modulus is acceptable, versus cases where more complex calculations are needed.
When Fracturing Doesn't Work
Authors: Jennings Alfred R. 
Published: December 2007

Abstract
Well stimulation by hydraulic fracturing is one of the most unique of the commonly used oilfield practices. In spite of the fact that the treatments are relatively expensive and substantial permanent changes are induced in a fractured well, most of today's fracturing treatment applications are based on theoretical engineering relationships. For a treatment to be effectively ‘designed’, a myriad of treatment parameters must be considered using sophisticated fracture modeling software.
For those not experienced with fracturing, the development of a successful treatment approach may seem quite confusing. How does one know the ‘best’ or the ‘optimum’ fracturing treatment approach? Several related questions arise concerning candidate selection and methods to evaluate the effectiveness of the treatment.
The success of well stimulation by fracturing is readily observable through well response. Most often the response can be seen just hours after the treatment. Throughout its history, sufficient success has been achieved with fracturing that it has become one of the most widely used techniques for improving well productivity.
There are many instances where fracturing has not worked, or at least has not provided desired improvement in well productivity. Failure with fracturing always carries an economic impact whether it involves a single well or influences the feasibility of developing an entire field.
The purpose of this paper is not to provide an analytical treatise into all the reasons why fracturing treatments may fail. Rather, two approaches will be taken to address the topic "when fracturing doesn't work". The first will deal with the historical perspective and pertinent improvements in fracturing over the last 50 years will be discussed. Secondly, a series of common reasons for fracturing failures will be described. Finally, suggestions will be offered to provide further improvements in the success of application of hydraulic fracturing.
The Tools of Sand Management
Authors: Tronvoll J. , Dusseault M. B. , Sanfilippo F. , Santarelli F. J. 
Published: December 2007

Abstract
Sand Management is an operating concept where traditional sand control means are not normally applied, and production is managed through monitoring and control of well pressures, fluid rates and sand influx. In the last four years, Sand Management in conventional oil and gas production has been implemented on a large number of wells in the North Sea and elsewhere. In almost all cases it has proven to be workable, and has led to the generation of highly favorable well skins because of self-cleanup associated with the episodic sand bursts that take place. These low skins have, in turn, led to higher productivity indexes, and each of the wells where sand management has been successful has displayed increased oil or gas production rates. Furthermore, expensive sand control devices are avoided and the feasibility of possible future well interventions is guaranteed.
Different analysis and design tools are needed to evaluate sand production probability, to quantify risk reduction, and to establish practical operational criteria for safe and optimum production. Such design tools include the capacity to predict sand production onset, sand quantities and sand production rates, equipment erosion risks, and the conditions at which the sand can be transported inside the production liner and surface lines. Also, an essential tool is a sand monitoring technology to allow real-time quantitative sand flux tracking. The application of these tools and how they help assess risks in Sand Management are illustrated through field examples in this paper. Methods of handling the uncertainties and risks are discussed. Data from the North Sea, where active Sand Management was applied to increase well production rates, are presented. Finally, ideas on how to apply sand management and hybrid completions in challenging environments such as HPHT fields, marginal fields and complex structures are discussed.
Adding Value to Well Completions via Effective Wellbore Cleanup: Smart Thinking, Big Rewards
Authors: Kume Nicholas , Uzoho Forster , Ogoke Victor , Abiodun Afolabi F. 
Published: December 2007

AbstractThere has been a proliferation of horizontal and high angle wells in West Africa, particularly in the Niger Delta. High production/injection rates and the need to optimize recovery from complex reservoir structures have been a justification for these wells. It has been noticed by many operators in this region that most of the horizontal and high angle wells either came in at a lower than expected potential or simply did not sustain initially high production rates. This paper details how a systematic analysis of critical factors; causing limited or poor productivity in over 30 horizontal and high angle wells, led to the identification of opportunities that have been so far exploited by the operators in West Africa to deliver superior value from their investments.This paper further shows that so far, a history of 100% technical success and greater than 200% improvement in delivering and exceeding projected potential production of treated wells has been achieved. Additionally there has been a consistent productivity improvement by using these techniques over all previously applied techniques, even for well draining from the same sands and having similar petrophysical characteristics. Payback time analysis on each well is included as part of the results. A technical comparison between treatment results from the New Combined Systems and the previously applied technologies (using a Normalised Productivity Index, Fluid rate, Skin factor and Well Inflow performance Indicators) is also included.Results of laboratory tests showing treatment effectiveness and compatibility with drill-in and formation fluids are also discussed to demonstrate the application of these techniques to different reservoir mineralogies and oil compositions.
Assessment of Sample Contamination by Downhole NMR Fluid Analysis
Authors: Bouton J. , Prammer M. G. , Masak P. , Menger S. 
Published: December 2007

AbstractA recently developed nuclear magnetic resonance (NMR) downhole fluid analyzer provides in-situ fluid characteristics at reservoir PVT conditions. The device is part of the Reservoir Description Tool (RDT*), a modular formation sampler and tester. This paper presents the theory and the experimental evidence that led to the use of NMR as a means to assess the amount of mud filtrate contained in the pumped formation fluid. In particular, the problem of differentiating oil base mud filtrate from connate hydrocarbons is difficult and has not been addressed by conventional measurements. NMR relaxometry uses the inherent differences in T1 time constant values and distributions to make these distinctions. The T1 data is available in real time and can be used to determine the optimum pump-out rates and durations while sampling reservoir fluids.
Imparting Directional Dependence on Log-Derived Permeability
Authors: Schön J. H. , Georgi D. T. , Fanini O. 
Published: December 2007

Abstract
Cost effective, efficient production of hydrocarbons depends on accurate reserves estimates, reservoir architecture, and hydrocarbon distribution. In addition, a complete reservoir description including both horizontal and vertical permeability is critical to efficient development strategy. Hydrocarbon recovery efficiency depends on many factors, but one key parameter is the ratio of vertical to horizontal permeability.
There are numerous ways to estimate permeability. It is now possible to estimate permeability from continuous formation evaluation measurements. However, it remains difficult to determine directional permeability. NMR logs are used routinely to estimate permeability, but NMR-derived permeability is based on scalar properties (e.g., ϕ, T2 distributions from NMR, bulk volume irreducible water) and is inherently a scalar property.
Few formation evaluation measurements provide directional information. Dip and image logs provide bed thickness and layer dip information. However, only the new multi-component induction instrument (3DEXSM) and crossed-dipole shear-wave acoustic tools provide direct measurements of macroscopic formation anisotropy.
In this paper, we explore theoretically and with real data the computation of permeability anisotropy. We use laminated sand models as well as macroscopic models based on the resistivity anisotropy measurements to estimate kv:kh ratios. In addition to multi-component induction data, we explore standalone and joint interpretation of NMR property variations to predict the macroscopic reservoir permeability anisotropy.
Use of an Integrated Approach for Estimating Petrophysical Properties in a Complex Fractured Reservoir: A Case History
Authors: Bona N. , Radaelli F. , Ortenzi A. , De Poli A. , Peduzzi C. , Giorgioni M. 
Published: December 2007

Abstract
Answering general questions such as "Where is the oil? How much oil is there? Can we extract it?" is a challenging task for a large fractured reservoir in Southern Italy. Various studies were conducted to gain more insight into the way the oil is distributed in the rock and the producibility of the different structures observable at the core scale (matrix, vugs, fissures). These included CryoSEM and GC-pyrolysis, pore size distribution measurements, SEM analysis on thin sections, and a number of non-conventional techniques that were specifically designed for that type of rock. NMR imaging was conducted on several whole core samples and the different porosity contributions (microporosity, vugs, and fissures) defined on a 3-D basis. An analytical approach based on the percolation theory was used to separate the permeability contributions and define the conditions under which vugs and fissures may form a conducting system. The inputs were distributions of pore throats, throat length, coordination number, fissure orientation and porosities. Wettability is a key parameter for production estimates, and we utilised a technique for measuring it in both microporosity and fissures, which makes use of dielectric constant measurements. All the data contributed to our current understanding of the reservoir.
The Beauly Oilfield - Creating and Sharing Value from a Marginal Discovery
Authors: Sherrard D. W. , Beckly A. , Howell P. , MacAskill A. 
Published: December 2007

Abstract
Beauly is one of the smallest developed oil fields in the North Sea with recoverable reserves of 3MMstb. A novel risk sharing contracting strategy involving owners, engineering contractors and transporters (collectively termed the Stakeholders) has delivered production of 10,000 b/d from a field which by most conventional measures would not have been developed. Initial good performance is being sustained and current expectations are that all Stakeholders will realise a successful commercial outcome. Key elements of the contracting methodology has been adopted by the North Sea industry body LOGIC for it’s Satellite Accelerator initiative.
Chemical Water & Gas Shutoff Technology – An Overview
Authors: Kabir A. H. 
Published: December 2007

Abstract
Numerous chemical options are available for addressing excessive water and gas production problems. The chemistry of most of these options is complicated. A petroleum engineer with an average chemistry background has difficulties understanding these to a level that enables him/her to choose and apply a proper option to the problem at hand. In this paper, we provide a brief overview of all chemical water/gas shutoff (WGSO) options available to date. Monomer systems, polymer gels, relative permeability modifying polymers, inorganic gels, plastics etc. are commonly used chemical options. Less common options include viscous flooding, selective plugging with induced mineral precipitation and other miscellaneous grouting materials. Pros and cons of all these options are also discussed.
A Comparison of Various Laboratory Techniques to Measure Thermodynamic Asphaltene Instability
Authors: Jamaluddin A. K. M. , Creek J. , Kabir C. S. , McFadden J. D. , D'Cruz D. , Joseph M. T. , Joshi N. , Ross B. 
Published: December 2007

Abstract
Asphaltenes are the n-pentane or n-heptane insoluble fractions of crude oil that remain in solution under reservoir temperature and pressure conditions. They are destabilized and start to precipitate when the pressure, temperature and/or composition changes occur during primary production. The precipitated asphaltene particles will then grow in size and may start to deposit onto the production string and/or flowlines, causing operational problems.
In this paper, our emphasis is to identify the first pressure and/or temperature conditions at which the asphaltene will start to precipitate for two reservoir oils. Four different laboratory techniques were independently used to define the onset of the asphaltene precipitation envelope. These methods are 1) gravimetric, 2) acoustic resonance, 3) light scattering, and 4) filtration. The gravimetric method was found to be precise and within the accuracy of the analytical methods. However, the method was time consuming. The acoustic resonance technique (ART) was fast and less subjective, but it did not define the lower asphaltene boundary. The interpretation of the onset pressure from the near-infrared (NIR) light-scattering technique (LST) was subjective to a degree. However, the NIR response defined the upper and lower boundaries of the asphaltene envelope and the bubblepoint pressure, as did the gravimetric technique. In a way similar to those of the gravimetric technique and LST, the filtration technique can also define the upper and lower asphaltene phase boundaries in addition to the bubblepoint pressure. The filtration technique is fast compared to gravimetric technique, but takes more time than the ART and LST methods.
Reservoir Characterization - Integrated Interpretation of Borehole Data and Surface Seismic Data
Authors: Cao H. , Endo T. , Yamamoto H. , Cao D. 
Published: December 2007

Abstract
Precise reservoir characterization is of primary importance to reservoir evaluation and optimization. Effective integration of borehole and surface seismic data is the key to achieve this objective. However, such an integration is well known to be a complex task due to various difficulties, e.g. different resolutions between well data and seismic.
In this paper, we show an integrated workflow in which borehole data and surface seismic data are integrated for reservoir characterization. The workflow consists of three steps as follow: Formation evaluation. Accurate petrophysical evaluation of well logs with other borehole data is carried out to build a petrophysical model that describes formation composition, lithology and fluid type.Fluid substitution and AVO modeling. This establishes the link between the seismic responses and petrophysical parameters. Borehole seismic data provide the calibration for the sonic data, and also the input for the anisotropic and inelastic effects. Fluid substitution investigates the effects of pore fluids on the propagation speeds of waves. AVO modeling generates offset dependent seismic responses for the models of interest with known petrophysical parameters.Seismic classification. Knowledge extrapolation is performed to populate the seismic volumes or sections with the calibrated AVO response obtained at the well location. A geostatistical and neural network analysis establishes the relationship between the seismic attributes and formation properties (lithofacies, porosity, permeability, pore fluids, etc) at the well location. The quantified knowledge between formation parameters and seismic response at the well location is exported to the rest of the seismic data (2D sections and/or 3D seismic volumes).
This workflow will reveal if there is enough acoustic difference between different lithofacies for them to be distinguished from seismic data. When there is sufficient acoustic difference between different lithofacies, the distribution and variation of these lithofacies can be tracked using the seismic data.
It can provide direct hydrocarbon indicators for the optimization of well locations. When the acoustic impedance difference between different fluids in the formation is large enough to be captured by AVO analysis, direct hydrocarbon detection is possible and the well locations can be optimized. This integrated approach adds tremendous value to the existing data and shows what is needed for future data acquisition.
Monte Carlo Simulation on the Effect of Fracture Characteristics on Reduction of Permeability by In-Situ Bacteria Growth
Authors: Han C. , Kang J. M. , Choe J. 
Published: December 2007

Abstract
We have simulated the effects of fracture characteristics on the reduction of effective permeability of fractured rocks due to in-situ bacteria growth. A solute is injected continuously to provide food for the growth of in-situ bacteria. We used a power law for fracture length distribution and a fBm for fracture aperture spatial distribution. The results show that in-situ bacteria growth reduces the permeability hyperbolically, but the porosity of backbone fracture does not change significantly. It shows that the reduction of the permeability proceeds faster for smaller values of length exponent and for larger values of Hurst exponent. The fracture length distribution has a stronger effect on the speed of permeability reduction than the aperture spatial distribution. The time needed to reduce permeability is inversely proportional to the hydraulic gradient.
Geosteering in a Complex Dolomitic Reservoir
Authors: Longis Christian , Ferment Denis Yves , Madjidi Ahmad 
Published: December 2007

Abstract
This paper presents the key of success for the development of a complex prospect, the Sarr dolomitic reservoir in the Kharir field, located onshore Yemen. The drilling of horizontal wells was considered to limit the early water encroachment observed on vertical producers and to improve both the oil production and the final recovery. A careful data acquisition program, a close cooperation between all the parties involved in the drilling process, with the implementation of common decision procedures, allowed geosteering in optimized reservoir targets, while preserving the safety of the horizontal drilling operation. The Kharir Sarr field is a multi-layered oil bearing dolomitic reservoir interbedded with tight limestones. Variable petrophysical properties characterize the dolomite in this field, following the geometry of elementary sedimentary facies, their stacking, their structural position, and finally their diagenetic history. On top of the structure, the reservoir is interpreted as dolomitized patchy biostromes, very difficult to target and to appraise with vertical wells.
Monitoring the data acquired in real-time, referenced to pre-job-modeling, provided the key elements for cautious decision-making on trajectory definition. The expertise developed in geological steering has contributed to boost oil production and add significant field reserves.