bluuebunny/crossref_metadata_2025_split huggingface dataset:
How To Estimate the Value of the Information (VOI) of a 4D Seismic Survey in One Offshore Giant Field
Authors: Steagall D. E. , Gomes J. A. T. , Oliveira R. M. , Ribeiro N. M. S. J. , Queiroz R. Q. , Carvalho M. R. J. , Souza C. Z. 
Published: December 2007

Abstract
The decision of acquiring or not, a new reservoir data goes through the difficult estimation of the economic value of this information. This paper presents the methodology used to estimate the value of information of a new seismic survey in the Marlim offshore giant field, located at Campos Basin, Brazil.
The main objective of this new 4D seismic is to enhance the geologic characterization and show the fluid changes in the reservoir that will allow an optimization and a decrease of the risk of the new well projects and the identification of new opportunities.
The estimate of the value of the information is based on the increment of the expected monetary value of the projects with a new 4D seismic data.
The developed methodology has the following steps: Identification of the projects of new locations that would be benefit with the new seismic up to 2010; the analysis of uncertainties;quantification of the risks of the projects; definition in types of expected gains of the new information; estimation of the success probability with and without new seismic; estimation of the net present value of each project with flow simulation; estimation of the expected monetary value of each project with and without new seismic using the decision tree technique; and finally the estimation of the value of seismic information to be acquired.
In this study the flow simulations were done respecting all production facilities, as processing capacities, well heads, slots in platforms and the schedule of initial operation of the wells, allowing more realistic results to support the decision to acquire a new 4D seismic.
NMR Applications For The Determination Of Sedimentary Facies And Porosity Systems In Carbonatic Core Plug Samples
Authors: Alfredo M. N. , José M. B. 
Published: December 2007

Abstract
The use of NMR techniques to determine petrophysical properties of reservoirs has been described in many previous works1,2. But, together with Gamma Ray logs, thin sections and capillary pressure curves, NMR can contribute further to the characterization of sedimentary environments and porosity systems.
In this work the results of the above mentioned techniques are presented. Almost 40 plug samples form a cored well in the Formation of Cretaceous age in Southwest Venezuela have been measured and described according to four sedimentary facies. We have found that the shape of the NMR T2 distributions and thin fine section images of each samples show a pattern related to the sedimentary facies the samples belong to. Another contribution of this work is that, unlike other reservoirs in Venezuela, the shape of the T2 distributions for the sample set can have one, two, three or four maxima or peaks depending on the porosity's system type e.g. intracrystalline, intercrystalline, fractures, synsedimentary fractured and vugs.
The correspondence between sedimentary facies and T2 distributions allows us to classify the rock quality as a function of the porosity, bound fluid and free fluid volumes expressed in the well known Timur-Coates permeability equation determined in each facies.
The results contribute to reduce the uncertainty in the petrophysical understanding of the reservoir and to improve the application of NMR technique in the sedimentology. Specifically, the relationship between T2 distribution patterns, thin section images and depositional environments extend the applications of NMR techniques beyond the classical determinations of petrophysical variables and fluid properties.
Efficient and Accurate Estimation of Permeability and Permeability Anisotropy from Straddle-Packer Formation Tester Measurements Using the Physics of Two-Phase Immiscible Flow and Invasion
Authors: Angeles R. , Lee H. J. , Alpak F. O. , Torres-Verdín C. , Sheng J. 
Published: December 2007

AbstractThis paper describes the successful application of a novel methodology to estimate permeability and permeability anisotropy from transient measurements of pressure acquired with a wireline straddle-packer formation tester. Unlike standard algorithms used for the interpretation of formation tester measurements, the methodology developed in this paper rigorously incorporates the physics of two-phase immiscible flow as well as the process of mudcake buildup and invasion. The effects of supercharge, skin, and convective transport of salt are also explicitly included in the estimation algorithm.An efficient 2D (cylindrical coordinates) implicit-pressure explicit-saturation finite-difference algorithm is used to simulate both the process of invasion and the pressure measurements acquired with the straddle-packer formation tester. Initial conditions for the simulation of formation tester measurements are determined by the spatial distributions of pressure and fluid saturation resulting from mud-filtrate invasion. Inversion is performed with a rigorous Levenberg-Marquardt nonlinear minimization algorithm. Sensitivity analyses are conducted to assess non-uniqueness and the impact of assumptions on rock-fluid and mud properties such as fluid viscosity, capillary pressure, relative permeability, mudcake growth, and time of invasion.Applications of the estimation algorithm to noisy synthetic measurements include homogeneous, anisotropic, layered, and multi-layered formations, for both low- and high-porosity rocks. We also study the effect of unaccounted impermeable bed boundaries on the inversion results. For cases where a-priori information can be sufficiently constrained, our inversion methodology provides reliable and accurate estimates of permeability and permeability anisotropy.
Numerical Well Testing: A Method to Use Transient Testing Results in Reservoir Simulation
Authors: Kamal M. M. , Pan Y. , Landa J. L. , Thomas O. O. 
Published: December 2007

Abstract
Transient testing is facing a challenge to have the information it provides incorporated in numerical simulators used to predict reservoir performance. Of greater importance, the lack of using the large number of dynamic in-situ reservoir parameters that can be determined from transient tests deprives operators from valuable data they can use to improve their reservoir management efforts. The main reason for the problem is that transient testing technology, developed largely via analytical solutions, provides average reservoir parameters not suited to the numerically discretized environment of current reservoir simulators. Previous efforts to include transient testing data in numerical reservoir simulation studies focused on history matching the pressure behavior during the test on a Cartesian-type plot just like matching stabilized production rates and pressures. Such approach neglects the wealth of information contained in the transient behavior of the tests.
A method called Numerical Well Testing (NWT) is proposed in this paper to preserve the information obtainable from traditional well test analysis and deliver it in a form suitable for direct use in numerical reservoir simulation. By using this method petroleum engineers will not shy away from using transient testing results just because they do not know how to incorporate averaged values in their discretized reservoir model.
NWT is a systematic method that consists of five steps starting with traditional well test analysis, locally refining grids based on the analysis results, modifying full field numerical models, upscaling, validating the updated model with production data, and predicting future reservoir performance. Details of how to accomplish each step are presented in the paper.
NWT was applied to field cases to demonstrate the applicability of the method and proved that incorporating results from the proposed NWT procedure improved reservoir description. Descriptions enhanced by NWT matched not only well test data but also field production data, and predicted different reservoir performances from those obtained via matching only production data. The paper concludes by describing the software developments needed to make NWT a routine analysis method.
Logging Tool Enables Fracture Characterization for Enhanced Field Recovery
Authors: Bailey J. R. , Sorem W. A. 
Published: December 2007

Abstract
ExxonMobil has developed a fracture mapping tool that uses acoustic methods to infer the geometry of induced hydraulic fractures. This tool may be run in the treatment well during fracturing, or it can be used in one or more offset monitoring wells. This tool, "TABS" for Triaxial Borehole Seismic, consists of an array of three triaxial geophone receivers, a telemetry sub to transmit the data to surface in real time on conventional 7-strand wireline, and an interface to a Gyrodata survey tool to provide the tool orientation when clamped. The tool subs are interconnected with "flex links" that are rigid in rotation but flexible in bending to allow each clamp arm to make independent coupling to the wellbore casing. The overall design is that of a logging tool, facilitating application via wellhead lubricators.
The geometry of the stimulated fracture has a significant impact on well productivity and recovery. In many applications, the reservoir depletion pattern is highly dependent on this geometry. Some key interactions between productivity and fracture geometry include: Well spacing is determined by the fracture length, formation properties, and depletion plan.Within this spacing constraint, well locations are determined by the induced fracture azimuth. Wells are placed to reduce interference among producers and to maximize conformance.Fracture height growth out of zone may lead to more costly stimulation treatments and lower well productivity. Modifications to the treatment design and adjustments to the selection of perforated intervals may increase well performance.
Working with the ExxonMobil Production Company, the TABS tool has been used to monitor 32 fracture treatments in 16 well entries. Results from several of these field applications will be used to describe the TABS technology and to demonstrate fracture geometry measurements.
Critical Parameters in Static and Dynamic Modeling of Tight Fluvial Sandstones
Authors: Apaydin O. G. , Iwere F. O. , Luneau B. , Ma Y. 
Published: December 2007

Abstract
This paper presents an integrated static and dynamic evaluation for selecting an appropriate geostatistical modeling method that best represents the production from a tight, stacked fluvial sandstone reservoir.The critical parameters investigated include sand body geometry, water saturation permeability, and hydraulic fracture properties.This effort involves the construction of several static and dynamic models within a one-square mile section of the field.
The study area contains about twenty-four wells with varying productivity or EUR, indicative of the reservoir heterogeneity.Several geological scenarios were developed to characterize facies/sand bodies, and multiple realizations of each scenario were investigated.Reservoir properties including porosity, water saturation and permeability were populated for each realization using sequential Gaussian simulation.
The geological scenarios incorporated variations of three widely used facies modeling algorithms: fluvial object, defined object, and sequential indicator simulation.These algorithms have their pros and cons in representing the distribution of reservoir facies.The model constraints, including facies at wellbores, global facies proportion, vertical facies probability, and areal facies probability constructed from well data were held constant between the scenarios, and infill well locations were used to evaluate the static facies prediction.
Reservoir dynamic models were used to rank individual scenario performance.The static and dynamic models share the same grid dimensions and no upscaling of reservoir properties was performed.The grid system and the recurrent data (completion, production and pressure histories) for the wells were consolidated in schedule files for input into a reservoir simulator.While there were no attempts to match the historical performance of the wells, boundary conditions and/or constraints derived from field operation were determined and used as production controls for the wells.Average hydraulic fracture properties were assigned to the fracture cells of each well, and gas production under depletion drive was simulated with the flow models thus built.The results were evaluated qualitatively and quantitatively to select the appropriate modeling workflow for constructing the static and dynamic models of the field.
Adsorption Kinetics of Surfactant Used in CO2-Foam Flooding Onto Berea Sandstone
Authors: Bai B. , Grigg R. B. , Liu Y. , Zeng Z. 
Published: December 2007

Abstract
This paper reports adsorption/desorption kinetics and equilibrium onto Berea sandstone for a surfactant used as a CO2-water foaming agent. Also, foam stability of the surfactant is compared before and after adsorption/desortion has occurred. Results show that this surfactant's adsorption onto and desorption from Berea sandstone took several days to reach equilibrium. Both adsorption and desorption were characterized by a short period of rapid adsorption/desorption followed by a longer period of slower adsorption/desorption. Both adsorption and desorption processes were best fit by a pseudo-second-order kinetic model. Coefficients of adsorption and desorption rate were determined. A method to predict equilibrium adsorption density using adsorption process data over a relative short period is proposed, which saves considerable time in determining complete adsorption isotherms. Surfactant concentration and temperature affect equilibrium density. Foam stability is affected by selective surfactant adsorption onto the rock.
Cement Mechanical Property Measurements Under Wellbore Conditions
Authors: Reddy B. R. , Santra A. , McMechan D. , Gray D. , Brenneis C. , Dunn R. 
Published: December 2007

Abstract
Cement integrity preservation during completion, stimulation, production, and even, during well abandonment is of critical importance for an operator from long-term economic, productivity, and safety perspectives. Traditionally, compressive strengths have been considered indicators of cement integrity. However, numerous squeeze cementing jobs regularly performed on completed wells are testament to the poor correlation between compressive strengths and cement integrity. Additional mechanical properties such as tensile and flexural strengths, elastic modulus, and Poisson's ratio are being taken into account with increasing frequency for maximizing the cement sheath performance during the life of the well. Unfortunately, all such measurements are performed on samples that have been cured, either under wellbore conditions (for example, pressure and temperature), or laboratory conditions (for example, atmospheric pressure) but tested at atmospheric pressure and temperature. Such properties may at best be useful for comparing different formulations in the selection process but do not provide information about the cement properties under downhole conditions.
Using ultrasonic shear wave and compression wave combination measurements, dynamic mechanical properties, such as elastic modulus, bulk modulus, and Poisson's ratio and compressive strength, are measured under pressure and temperature. These measurements are compared with mechanical properties obtained from load vs. displacement under static conditions and acoustic compression and shear wave measurements at atmospheric pressure and temperature. Correlations are made for several slurries. The results are presented. The results also will present cases where the measurements made using this method demonstrated unique advantages over the conventional load vs. displacement techniques.
Integration of Geologic and Dynamic Models for History Matching, Medusa Field
Authors: Lach J. , McMillen K. , Archer R. , Holland J. , Depauw R. , Ludvigsen B. E. 
Published: December 2007

Abstract
Medusa Field in the Gulf of Mexico produces from turbidite sandstone reservoirs at depths between 10,000 and 14,000 feet. Production from the field commenced in December 2003, and six wells are producing at a rate of 40,000 BOE/D. Well A-3 is producing from the T4B reservoir at average oil rates in excess of 10,000 STB/D.
The late Miocene T4B reservoir was deposited in a turbidite channel/levee environment with extensive thin-bedded levee and isolated massive sand channel-splay facies. Stratigraphic cross sections and seismic amplitudes show rapid lateral change from levee to channel-splay facies. Depositional slopes, consisting of the east-facing levee flank and west-facing regional slope, and syn-depositional normal faulting control the location and thickness of channel-splay deposition. Conventional core in one T4B well provides information on depositional facies, reservoir properties and rock compaction.
The decline of reservoir pressure early in the producing life indicated that well A-3 was connected to a smaller oil volume than estimated from pre-production models. However later performance, the ability to sustain oil flow rate and a slowing of the rate of reservoir pressure decline, suggested communication between the higher quality channel-splay and levee facies and a larger OOIP than indicated by the early performance. The eventual rise in producing gas-oil ratio and the onset of minor water production also affected the well's performance.
Simulation history matching commenced using pre-production reservoir characterization models with the objective to forecast well A-3 production and to evaluate the potential for a previously planned second well completion in the zone.Traditional history matching using the original static model was not satisfactory.
MEPO®, an optimization tool for assisted history matching, was used to complete the history match study. Multiple equiprobable history matches were obtained varying fault and facies transmissibility, fluid PVT, rock compaction curves, and critical gas saturation. The reserves and production profile risk for a future well completion have been evaluated with a range of the history match results.
Reconciling Prior Geologic Information with Production Data Using Streamlines: Application to a Giant Middle-Eastern Oil Field
Authors: Fenwick D. , Thiele M. , Agil M. , Hussain A. , Al-Humam F. , Caers J. 
Published: December 2007

Abstract
Effective history matching of real fields requires the resolution of two outstanding problems. First, a conflict may exist between the production data and the existing geological model built solely from static information. In resolving this problem one must relate the inherent multi-scale nature of production data to petrophysical properties of the reservoir at the proper scale. Second, during model updates, geological consistency must be maintained by honoring the prior geologic information. The geoscientist has to choose what prior information is well know (hence fixed), and what is uncertain (hence modifiable). In many instances, the type of geostatistical algorithm is fixed, while key prior geostatistical parameters should be perturbed (e.g. facies proportions, petrophysical properties trends, variogram parameters, and random seed).
We propose a new methodology that addresses these problems. First, streamlines are used to relate the production data to petrophysical properties at multiple scales. A combination of geostatistical tools (locally varying mean and probability perturbation method) are then used to jointly map multi-scale corrections back to the geological model through changes of the prior geostatistical parameters. The mapping reconciles the fixed prior geologic information with the production data. The geological model is then explicitly recreated by re-running the geostatistical simulation. This approach differs from other history matching techniques where the petrophysical properties of each grid block are modified directly. While a successful history match may be obtained, the resulting model may be inconsistent with important prior information, hence retaining little predictive power.
The methodology is demonstrated by applying it to history matching a giant Saudi Arabian carbonate oil reservoir. This reservoir has over 500 producers and over 50 years of historical data with dramatically changing field conditions. In the past, several attempts were made to manually history matching this reservoir. The process was found to be extremely time consuming, involving dramatic local permeability changes which are often not supported by geological data. By applying the new approach, rather than correcting permeability manually, the corrections supplied by the streamlines were used to constrain the geostatistical algorithms, thereby ensuring a consistent geological scenario at every iteration.
Pseudosteady-State Analysis of Finite Conductivity Vertical Fractures
Authors: Meyer B. R. , Jacot R. H. 
Published: December 2007

Abstract
A new solution methodology for pseudosteady-state behavior of a well with a finite-conductivity vertical fracture is formulated using a reservoir/fracture domain resistivity concept. The formulation encompasses a transformed resistivity domain based on an equivalent or effective wellbore radius. The resulting pseudosteady solution is presented in the form of the dimensionless productivity index (JD).
Some of the major advantages of this pseudosteady solution for finite-conductivity vertical fractures are 1) the methodology is based on fundamental principles, 2) the solution is analytical and easily implemented, 3) the equations are formulated for rectangular reservoirs, 4) the model includes wellbore flow (i.e., wellbore radius effect) which is important for low-conductivity fractures, and 5) the formulation accounts for a piece-wise continuous linearly varying fracture conductivity including: proppant tail-ins, over-flushing, pinch zones, choked flow (internal), and external skin mechanisms.
The stimulation ratios for finite-conductivity fractures with an undamaged well are compared with those of McGuire and Sikora1 (1960), and Holditch2 (1974). The accuracy and validity of the pseudosteady model is also illustrated by comparison with the works of Prats3,4 (1961,1962), Gringarten et al.5,6 (1974), Cinco-Ley et al.7–10 (1978,1981), Barker and Ramey11 (1978), and Valko and Economides12 (1998).
A summary of the fundamental building blocks, effective wellbore radius concept, pseudo-skin functions and fracture skin are discussed. An improvement to Gringarten's dimensionless productivity solution for infinite-conductivity vertical fractures in rectangular closed reservoirs is also presented.