bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling Optimization Software Verified in the North Sea
Authors: Bratli R.K. , Hareland G. , Stene F. , Dunsaed G.W. , Gjelstad G. 
Published: December 2007

Abstract
This paper presents the introduction, application and verification of a new drilling optimization approach. During the past decades rate of penetration (ROP) models for all types of drilling bits were developed and verified. The unique software uses these models in a new approach that optimizes the drilling cost on each hole section. The simulation of ROP every foot gives the capability to simulate the effects of all operating conditions, bit design, bit wear and formation properties.
All the penetration rate models used can be inverted to solve for rock strength if ROP, operating conditions, lithology percentage and field reported bit wear is known. This imply that if one well has been drilled, and the penetration rates are inverted, a foot by foot strength is obtained, by integrating over each individual bit run until the field reported bit wear matches the calculated. This strength is then used as input for simulation, and it is shown that the drilling cost for one particular 12,25" section can be reduced as much as 45-50 percent by changing bit design and operating conditions.
This approach has been verified with North Sea data where the generated rock strength from the 12,25" section has been used as input to simulate the ROP and rotating time. These simulations compare well with the measurements of ROP, made in the two following wellbores drilled in the same field. Simulating ROP using drilling data from a well in a nearby field also gave promising comparisons.

Introduction
The DRilling OPtimzation Simulator (DROPS) is developed to reduce the cost of future wells based on a Geological Drilling Log (GDL), created from the data collected in a previous well drilled in the same area. The GDL is created using ROP models inverted to calculate rock compressive strength. The simulator has the capability of simulating any combination of operating conditions, bit designs, pull depths, hydraulics, WOB and RPM. The basic idea behind DROPS is to simulate the drilling operation prior to the actual drilling, and to find the optimum cost level. Simulations to verify the software (drill behinds) have been performed using actual field data from the North Sea, provided by Saga Petroleum ASA, well A and B. Data from well C, provided by Statoil, have also been used in the drill behind simulations. The simulated ROP results from the drill behind compares well with the results for actual measured ROP and cumulative rotating time, which are promising for further development and application of the method. Based on the comparison some cost optimizations for future wells in this region have also been performed. The cost reductions obtained indicate potential cost savings of 45-50 percent of total drilling cost per well, compared to the current industry practice in the area. By using this methodology in the planning process the most cost effective drilling program can be obtained.
Tools for Predicting and Avoiding Gas Migration after Casing Cementing in Brazilian Fields
Authors: Martins A. L. , Campos G. , Silva M. G. P. , Miranda C. R. , Teixeira K. C. 
Published: December 2007

AbstractThe occurrence of gas migration problems in several oilfieds in Brazil, motivated an experimental computational study conducted on PETROBRAS R&D Center. Lab and pilot scale equipments were used to define basic guidelines for the success of a cementing operation in front of gas zones. The necessity of a team work, involving lab, design and operation teams is emphasized. This joint effort aims the optimization of well conditioning, slurry design and displacement programs. Adequate evolution of gel strengths and consistency, pseudoplasticity and minimum fluid loss and free water are the main variables for optimum slurry design. Analysis of historic cases of cementing failures help in the establishment of operational guidelines for future jobs
Core-Data Management for Reservoir Characterization Studies
Authors: Sombra Cristiano L. , Sarzenski Darci J. , Derraik André L. B. , Hester Anna M. , Borges Renato F. , Ierusalimschy Roberto 
Published: December 2007

Abstract
Core-analysis data, either qualitative (i.e., lithology, grain size, oil staining, facies, diagenetic attributes) or quantitative (i.e., porosity, permeability, fluid saturation, petrographie quantifications), can be input data for formation evaluation and reservoir characterization procedures, such as log calibration, variogram modelling, search for analogue outcrops, etc. The quality of reservoir 2D and 3D models, such as volumetric analysis and stochastic modelling, depends on core information.
A major challenge while using core data to calibrate electric logs is to achieve the most precise matching between different depth scales. In thinly stratified reservoirs, small differences in depth can produce significant distortions on property correlations. Moreover, an effective calibration exercise depends upon handling a series of parameters altogether, and mathematic procedures seem to fail in many commonly used situations. Digitalization of core descriptions through an interactive graphical interface, based on the idea of core objects, brought an efficient solution to this problem. A continuous piece of core, with all the geological descriptions, sampling and laboratory quantifications related to that interval, defines a core object. The most usual information associated to that object are grain size, lithology, texture, oil staining, cementation, plug porosity and permeability, minipermeametry measurements and core-gamma readings, all of which being graphically edited and visualized. Moving core objects up and down will adjust them to electric log curves, what will guarantee consistency between these two data sources.
After core and log data are matched, they can be exported as output files to any log analysis package or to a statistical package, on which more sophisticated log calibrations are achieved These output files can be useful for many distinctive reservoir characterization applications, some of which are discussed in this paper: basic statistics and regression analysis from core data, core-log calibration, cut off determination, outcrop versus subsurface analogy, variogram modelling and calibration of acoustic properties.
Important Issues in Cuttings Transport for Drilling Directional Wells
Authors: Azar J. J. , Sanchez R. Alfredo 
Published: December 2007

Abstract
There are many factors that impact on hole cleaning while drilling directional wells for hydrocarbon recovery. Those that are most prevalent include: annular drilling fluid velocityhole inclination angledrillstring rotationannulus eccentricityrate of penetrationdrilling fluid propertiescharacteristics of drilled cuttings
In this paper the authors discuss the above factors and their field limitations. In addition, the key issues that need to be addressed for the development of a universal and reliable model in hole cleaning are identified.
A Generalized Methodology for Minimum Miscibility Pressure
Authors: Ahmed Tarek 
Published: December 2007

Abstract
This paper presents a generalized methodology for predicting the MMP required for the multi-contact miscible displacement of crude oil systems by gas injection. The approach is based on applying the Peng and Robinson Equation of State; in a modified form, in conjunction with a newly introduced "Miscibility Function". The miscibility function is designed to provide accurate predictions of the MMP. It is the objective of this paper to demonstrate how this miscibility function can be used to determine the necessary conditions required for miscible displacement of hydrocarbon systems by gas injection. The validity and the use of the proposed methodology is illustrated by matching several experimentally measured minimum miscibility pressure values.
Computation of Wag Process and Experimental Verification of Fractional Flow Hysterisis in Porous Media
Authors: Cunha M.C. , Bonet E.J. , Correa A.C.F. 
Published: December 2007

Abstract
We present a methodology for computation of the water alternated gas (WAG) injection process for oil recovery. In this methodology we use the method of characteristics to construct the analytical solution of the displacement, and we design a computer program to perform the intermediary steps required for the effective calculation of the solutions. We also analyze the effect of the hysterisis phenomenon on the fluid displacement in porous media, due to the sequential imbibition and drainage process. In our analysis we use published analytical hysteretical models and experimental results acquired in our laboratory apparatus. The comparison between experimental and analytical results are presented.

Introduction
Water-Alternate-Gas is an effective process to enhance oil recovery. The process is modeled by a system of hyperbolic partial differential equations; the conservation of water-hydrocarbon phase and the conservation of the gas component. As it is known, there are discontinuities in the solution of this kind of problems. Also the sequence of water and gas injection means that the boundary condition is a step function. Therefore, there are several jumps in the water saturation profile. Simulation of this process using usual numerical methods, such as finite difference and finite elements, is impractical, since the numerical dispersion near the jumps will propagate and interact themselves, destroying the character of the solution.
In this paper we describe a semi-analytical method to solve the WAG model.
We use the characteristic method to construct simple waves and the coherence principle to obtain compatible connections of simple waves that solve the Riemann problem, with arbitrary left and right states, for the model.
The effective calculations of the front trajectories, water saturations and gas concentrations are done by means of a computer code that perform the intermediary computations. On the other hand, the water-alternated-gas injection causes a sequence of imbibition and drainage process in the porous media. This process is the cause of the appearance of the hysterisis in the relative permeabilities curves, and in consequence, the hysterisis in the fractional flow curves. In this paper we also analyze the hysterisis effect on fluid displacement in porous media. We restricted our study to two-phase water and oil flow. Our hysterisis analysis is performed using experimental results, analytical formulation and calculation, and the comparison between experimental and analytical results.
Sand Production in Ultra-Weak Sandstones: Is Sand Control Absolutely Necessary?
Authors: Tronvoll J. , Papamichos E. , Skjaerstein A. , Sanfilippo F. 
Published: December 2007

Abstract
This study is focusing on sand production processes in weak sandstone formations with a uniaxial compressive strength in the range of 0 – 10 MPa, with special emphasis on the ultra-weak facies where uniaxial compression tests hardly can be conducted. The relative influence of rock mechanical properties on rock failure and sand production modes is addressed to understand sand production data from wells in a weakly consolidated basin. Results of physical model experiments of sand production from boreholes and perforation cavities as well as numerical simulations have been used along with the field data to evaluate different criteria for the onset of sand production in ultra-weak formations. It is shown how in particular the shallow and weakest strata deviates from the classical behavior of more competent formations, and a simple empirical criterion for estimation of the conditions for onset of sand production is proposed. Finally, alternatives to classical sand control strategies are discussed, which directly take into account the nature of weak sandstone.
Revitalization of Mature Reservoirs in Lagomar Segregation, Lake Maracaibo, Western Venezuela
Authors: Muñoz Pedro J. , Antunez Angel , Medina Mileida , Parra Nestor , Bengochea Xiomara , Agostini Nélida , Herrera Sol 
Published: December 2007

Abstract
The Lagomar production Unit covers Blocks I, II and XII of Maraven's concession in the Lake Maracaibo basin, Western Venezuela. The Unit consists of 114 reservoirs mostly of Eocene age, it has 740 wells drilled to date and has been on production for more than 40 years. The combined total OOIP of these reservoirs stands in excess of 8,487 MMSTB and at the end of 1996, 663 MMSTB remain as proven and 44 MMSTB as probable reserves. These substantial volumes of remaining reserves make the Lagomar Unit as one of the most attractive producing areas within Maraven's operating plan.
Until 1992, the Lagomar Unit had been on a steady decline mostly because of primary depletion and with limited efforts of secondary recovery. Detailed characterization of the reservoirs was lacking up to this time and the reservoir mechanism and the fluid movements, specially in terms of secondary recovery were not well understood. A revitalization program for increasing production and ultimate recoveries was undertaken at this time in the form of a multidisciplinary team effort. The team was charged with increasing the production and reserves over the following five years. The strategies included, a) recompletion of old wells, b) drilling of new wells including the re-entry and horizontal wells, c) commingled production of multiple horizons, d) slimhole, geologically targeted infill and appraisal drilling, e) reactivation of Basal La Rosa reservoir.
Implementing the revitalization strategies increased the drilling activity to 82 wells and 109 recompletions during 1992-1996. Directional drilling technology was successfully applied in the development well VLA-1035 and in the reentry sections of the wells, VLA-780 and VLA-807 in the VLA-6, C-7 reservoir. The productivity of Basal La Rosa increased from 3,000 to 19,000 STB/D. Commingling the production of C-2 and BLR reservoirs increased the production fourfold. The application of geologically targeted infill drilling (19 wells) and slimhole drilling (18 wells) increased the production output by another 20,000 STB/D.
The implementation of these technological alternatives favorably impacted the Lagomar production rate with an increase from 59,000 STB/D in 1992 to 81,000 STB/D in mid-1996. This paper describes the various strategies of revitalizing the Lagomar Segregation Unit and how these were implemented in a multidiscilplinary manner for achieving optimum results.
The La Rosa Basal Sand, Block I, Venezuela. Strategies and Expectations
Authors: León Alfredo , Casas Jhonny , Agostini Nélida , Bengochea Xiomara , Salamanca Lourdes , Muñoz Pedro , Parra Nestor 
Published: December 2007

Abstract
The La Rosa Basal Sand (Miocene), known in some areas as Santa Barbara Member, was discovered in 1954 as a pool for Block I area in Lake Maracaibo basin, with a relatively poor success during the next 40 years of production.
Since 1993 however, an aggresive policy of workovers and drilling was undertaken increasing by over 300 % the total production of medium and light oil. These activities were based upon the recommendations of several multidisciplinary team projects.
The La Rosa Basal Sand is a 5–60 ft thick sandstone deposited in a fluvio deltaic environment overlaying an unconformity which truncated Eocene succesions (Pauji and/or Misoa formations). Lateral continuity varies from south to north and it is feasible not only to observe new sand bodies but also coalescent effect with the underlying Eocene productive sands. The La Rosa Basal Sand is overlain by a 100′–200′ thick marine shale, known as La Rosa Shale.
Change of paradigm in the reservoir management was mainly a consequence of the result of well VLA-1185, upon the west flank of the Block which also demanded a revision of the petrophysical parameters. Its initial production of 1,300 BPD and 0.3 % water, was difficult to explain considering resistivity values of only 8–10 Ohm-m, a parameter which had been long considered to indicate high water saturation. Such parameter subestimated remnant reserves and in some cases supported rejection of some well locations. Additionally new core data has helped to better understand reservoir behaviour and predict future activities. During the last four years seismic interpretation, stratigraphic well by well correlation, structural and isopach maps and production history matching have been updated by information from new wells which have acted as a support for a slimhole campaign. Consequently, geologically targeted infill wells and no conventional workovers, increased production from 4000 BPD to 18400 BPD (Mid, 1996).
Three-Dimensional Multiphase Flow Simulation in Petroleum Reservoirs using the Mass Fractions as Dependent Variables
Authors: Maliska C.R. , da Silva A.F.C. , Czesnat A.O. , Lucianetti R.M. 
Published: December 2007

Abstract
This paper describes a numerical methodology for solving three-dimensional multiphase flow in petroleum reservoirs. The mathematical model encompasses the Darcy's equations and the mass conservation equation for the oil, gas and water components. To account for the gas phase appearance/disappearance, without employing special strategies, the method uses the mass fractions as dependent variables. The mathematical model uses boundary-fitted coordinates which permits to deal with complex reservoir boundaries and offers the opportunity of better representing curvilinear geological structures. The solution is fully implicit and includes the proposition of a well model for non-orthogonal discretization.

Introduction
The simulation of the multiphase flow of oil, gas and water in porous media are usually carried out using the saturation and pressure as dependent variables. However, there are thermodynamic conditions in petroleum reservoirs in which the gas is dissolved in the oil, but the gas phase is absent. Since the saturation is related to the existence of the phase, when the gas phase disappears, but the gas component is still present. in the oil phase, the numerical scheme must take into account the phase appearance/disappearance. To deal with this problem it is necessary to change the variables during the simulation, or to avoid the phase disappearance, keeping a residual value for the saturation. These strategies poses numerical difficults and may cause instabilities during the solution procedure.
One alternative for by-passing this problem is to use the mass fractions of the components as dependent variables, as done in Prais and Campagnolo and Britto. This guarantees that, in the case of the gas phase disappearance, the mass fraction of the gas component, representing the total mass of gas dissolved in the other phases, will be non-zero.
This paper presents a numerical method for solving 3D multiphase flow of oil, water and gas in complex reservoirs using the mass fractions as dependent variables and a fully implicit formulation. For handling the complex geometries of the reservoirs, a non-orthogonal boundary-fitted coordinate system is used. This type of structured discretization has been previously used by Maliska et al for modeling two and three phase flows with IMPES formulation. Curvilinear orthogonal grids have been used in the past by Hirasaki and O'Dell, Sharp and Anderson and Robertson and Woo among others.
The model is applied to solve three-dimensional two-phase and three-phase flows in petroleum reservoirs.
Computing the Effective Permeability by Finite Differences, Finite Elements, and Mixed-Hybrid Finite Elements
Authors: Ribeiro R.F. , Romeu R.K. 
Published: December 2007

Abstract
Upscaling the absolute permeability is a key operation in the reservoir characterization process. Although quick analytical estimates can be acceptable in some applications, numerical simulation is considered the reference method for the general case. This paper examines the performance of three numerical methods - finite differences (FD), finite elements (FE), and mixed-hybrid finite elements (MHFE) - on the computation of the effective permeability in coarse and refined numerical grids for some examples of heterogeneous media. Results show that the errors are systematic: the FD method underestimates and the FE method overestimates the exact answer in coarse grid discretization Averaging both estimates seems to compensate these errors. Although it follows the general behavior of the FD method, underestimating the exact answer, the MHFE method produces the best results for a given level of grid refinement or for a given size of the linear system.

Introduction
Modern geological and geostatistical modeling allows a reservoir heterogeneity description that is too much detailed to be directly handled by numerical flow simulators due to limited computing power. Hence, we have to compute effective or equivalent properties on a coarser grid, trying to keep the essence of the fine scale information for engineering purposes. This is known as the upscaling process, which has turned out a critical step for the reservoir studies. Among all properties to upscale, the absolute permeability has been the most studied.
The definition of the effective permeability, Keff, is not unique. The idea is to replace a heterogeneous permeability medium by a homogeneous one in such a way that the substitution is equivalent for certain purposes and situations - but not, in general, for all purposes and situations. Indeed, when we replace many data by one single data, we generally loose information, and the equivalence is only relative. Depending upon the selected criteria, the results of Keff may be different. At the end of this introduction, we will precisely state how Keff is defined in this paper.
There are two classes of methods for computing the equivalent permeability: analytical methods and numerical methods. Exact analytical solutions apply only for special cases, like in parallel and in series configurations. A more interesting case is the isotropic lognormal 2D medium for which the equivalent permeability is equal to the geometric mean. Some analytical results have been derived from perturbation methods or from the effective medium theory, which both involve special hypothesis. Different kinds of spatial averages provide quick estimates useful for many practical applications.