bluuebunny/crossref_metadata_2025 huggingface dataset:
Permeability and Saturation Evaluation in Deepwater Turbidite Utilizing Logging-While-Drilling Low-Gradient Magnetic Resonance
Authors: Turco Kevin , Brenneke Jim , Jebutu Segun , Kirkwood Andrew , Thern Holger , Chemali Roland , Kruspe Thomas
Published: December 2007

The economic recovery of hydrocarbons from deepwater reservoirs continues to be a major challenge facing the exploration and production industry, not just contending with the multitude of market uncertainties, but also, more importantly, reservoir deliverability uncertainties associated with deeply deposited pay targets. One large field subject of this study is such, deposited in stacked Pliocene sandstones. These are high net-to-gross, with predominant very finegrained sands. The efficient sweep of the oil in place requires a detailed understanding of the network of the reservoir pore structure, and the permeability distribution and capillary bound fluids.

To better understand and characterize the permeability and to help quantify the potential reserves, a novel low gradient magnetic resonance LWD tool for application on conventional drilling assemblies was used. This is a major departure from the more conventional techniques which use high gradient magnetic resonance on post-drilled wireline platforms. Advantages of an LWD approach are twofold; the wellbore is in good condition at the time of drilling, yielding high quality data, and the gain in rig time is significant.

The high quality magnetic resonance dataset acquired was confirmed by overlaying with stationary measurements. The data was integrated with offset core data to normalize permeability models and saturation functions. LWD density images acquired during drilling were also used to provide detailed visualizations of the internal laminations of the turbidites, as well as a reservoir structural setting. Formation pressures and mobility measurements acquired during drilling were also integrated in the normalization process to characterize the deliverability of the sands.

The resulting permeability model was used to study and redesign future development in the field. The saturation results also provide an improvement over the previous resistivity-only based saturation values, which were pessimistic due to the fine-grained structure of the reservoir sands.
Modeling of Expandable Slotted Tubulars
Authors: Li Zifeng , Yao Dongping , Samuel G. Robello
Published: December 2007

Advanced technologies are implemented for successful completion of wells and have become paramount objective especially in high-risk, high-cost environments, such as ultradeep water extended reach wells. Challenges are associated not only with complex well architecture but also completing the wells successfully using slotted tubulars, slotted liners and etc. Expandable slotted tubulars have been found to improve well production, reduce sand production and thereby reduce well costs compared with conventional approaches to sand control. While performing these completion operations the maximum running hook loads and static drag encountered during pre and post expansion process are indispensable for making appropriate well-completion decisions. Comparatively little research or modeling has been done to estimate these operating parameters. Traditionally, operating parameters such as torque and drag are estimated using the traditional torque and drag calculations with adjusted friction factors. This will result in under estimation of the values and pose problem in successfully completing the zone. Unduly conservative design or under estimation may pose poor result and lead to undesirable increase in the well cost and may be significant in challenging wells. To avoid this, a simple mathematical model has been developed and presented in this paper. Several simulations were carried out with synthetic as well actual data and have been found that the model prediction is very good as compared to the actual data. This paper documents the comparison between the predicted mathematical simulation results with the actual data.
Development and Application of New Computational Procedures for Modeling Miscible Gas Injection in Fractured Reservoirs
Authors: Hui Mun-Hong , Gong Bin , Karimi-Fard Mohammad , Durlofsky Louis J.
Published: December 2007

Detailed geological characterizations of naturally fractured reservoirs are commonly in the form of discrete fracture models, in which each fracture is defined explicitly. The efficient simulation of flow processes in such models poses a great challenge. In recent work, we developed systematic procedures for upscaling discrete fracture models to coarse-scale continuum descriptions referred to as multiple subregion (MSR) models. In this work, we extend these formulations to generate full dual-porosity, dual-permeability MSR models and additionally introduce the use of global single-phase flow information in the computation of the upscaled interblock transmissibilities required by the method. The resulting models are used for waterflood simulations and, more interestingly, for compositional simulations of first-contact-miscible gas injection. In a series of flow simulations involving both connected and disconnected fracture systems, it is shown that the MSR method provides results of reasonable accuracy, relative to the reference DFM solutions, for both oil-water and compositional oil-gas simulations with six pseudocomponents. Computational speedups of order 1000 are achieved for the compositional models.
A Modeling Study of the Role of Selected Minerals in Enhancing CO2 Mineralization During CO2 Aquifer Storage
Authors: Thibeau S. , Nghiem L. X. , Ohkuma H.
Published: December 2007

CO2 mineralization is a process whereby the CO2 that is injected into a geological formation dissolves into the formation water, reacts with the in situ minerals and ions, and precipitates as carbonate minerals. This process governs the long-term fate of the injected CO2 and ensures a safe storage once CO2 has been converted into minerals.

In a previous study involving the modelling of the long-term fate of CO2 in the Utsira aquifer storage, the authors observed that CO2 mineralization was not possible if mineral reactions were limited to Calcite and Dolomite precipitation and dissolution.

Indeed, to mineralize CO2, non carbonate minerals that are present in the formation have to: –dissolve in order to buffer the pH decrease resulting from the CO2 injection;–provide cations such as Ca2+, Mg2+, Fe2+ to the formation water;–not release bicarbonate (HCO3−) to the formation water.

Then the released cations react with HCO3− resulting from the dissolution of the injected CO2 and precipitate new carbonate minerals.

In this study, the CO2 mineralization process is modelled, taking into consideration various possible reactive pathways.

In the first step, the different reactive pathways are investigated in terms of reactive potential, CO2 mineralization potential and consequences on the porous network.

In the second step, simulation of flow and dissolution of CO2 together with geochemical reactions is performed to examine the mineralization process in space and time for two different time scales:

– 1000 years with a finer grid to examine how chemistry interacts with the CO2 dissolution process; and – 18,000 years with a coarser scale to reach geochemical equilibrium in the aquifer.

This work shows that a limited amount of non-carbonate reactive minerals (for a given time scale) can contribute to the mineralization of CO2 that is significant for an industrial CO2 storage project. As such, the identification of the reactive pathways leading to CO2 mineralization is a key step to evaluate the long-term fate of the injected CO2 in a geological storage project.
Predicting Undulating Well Performance
Authors: Kamkom R. , Zhu D. , Bond A.
Published: December 2007

Undulating wells are one of the alternatives to horizontal wells in field developments for extremely low vertical permeability formations. Undulating wells offer higher reservoir exposure and they do not depend on vertical permeability as much as horizontal wells do. This makes undulating well trajectory sometimes more attractive than horizontal wells.

Although undulating wells have been used in the field, predicting and understanding well performance is still a challenge. In the past, we have presented an analytical model that uses a segmented vertical well model with a slanted skin factor to estimate undulating well performance. The analytical model works well under certain formation and well structure conditions. In this paper, we will present a more comprehensive model for undulating well performance. The model evaluates undulating well performance in a parallelepiped reservoir based on a line source solution. The well can be located anywhere in the reservoir. The result is also compared with the previously developed analytical model to identify the conditions that the analytical model can be applied.

Field examples are used in the paper to illustrate optimizing undulating well performance by the model. The Cosmopolitan Field, Cook Inlet Alaska, and the Oooguruk Field, North Slope Alaska, are planned for development with undulating horizontal wells. Both reservoirs are challenged with relatively low permeability, low kv/kh ratios and moderate viscosity oil. Undulating horizontal wells are needed to overcome these issues and deliver commercial production rates. The performance model developed in this study demonstrated the additional value of an undulating well over a conventional horizontal well, which provided a key support in well design and field development plan.
A Robust Steady-State Model for Flowing-Fluid Temperature in Complex Wells
Authors: Hasan A. R. , Kabir C. S. , Wang X.
Published: December 2007

This paper presents an analytic model for computing the wellbore-fluid-temperature profile for steady fluid flow. Although wells with constant-deviation angle can be handled with existing analytic models, complex well architectures demand rigorous treatment. For example, changing geothermal-temperature gradient and deepwater wells present significant challenges. Additionally, available analytic models rarely provide calculation methods for various required thermal parameters, such as the Joule-Thompson coefficient and fluid expansivity.

The approach taken in this study entails dividing the wellbore into many sections of uniform thermal properties and deviation angle. The governing differential equation is solved for each section, with fluid temperature from the prior section as the boundary condition. This piecewise approach makes the model versatile, allowing step-by-step calculation of fluid temperature for the entire wellbore. We present simple, thermodynamically sound approaches for estimating thermal parameters.

Good success is indicated when performance of the proposed model is compared with data from three wells; producing two-phase gas/oil mixture, single-phase oil, and single-phase gas. Sensitivity of the estimated fluid temperatures to various thermal properties is also examined using our model. Overall, the effects of Joule-Thompson coefficient and liquid expansivity are found to be significant.
An Iterative Ensemble Kalman Filter for Data Assimilation
Authors: Gaoming Li , Reynolds A. C.
Published: December 2007

The ensemble Kalman filter (EnKF) is a subject of intensive investigation for use as a reservoir management tool. For strongly nonlinear problems, however, EnKF can fail to achieve an acceptable data match at certain times in the assimilation process. Here, we provide iterative EnKF procedures to remedy this deficiency and explore the validity of these iterative methods compared to standard EnKF by considering two examples, one of which is pertains to a simple problem where the posterior probability density function has two modes. In both examples, we are able to obtain better data matches using iterative methods than with standard EnKF.

In Appendix A, we enumerate the assumptions that must hold in order to show that EnKF provides a correct sampling of the probability distribution for the random variables. This derivation calls into question the common derivation in which one adds the data to the original combined state vector of model parameters and dynamical variables. In fact, it appears that there is no assurance that this trick for turning a nonlinear problem into a linear problem results in a correct sampling of the pdf one wishes to sample. However, we show that augmenting the state vector with the data results in a correct procedure for sampling the pdf if at every data assimilation step, the predicted data vector is a linear function of the combined (unaugmented) state vector and the average predicted data vector is equal to the predicted data evaluated at the average of the predicted combined state vector. Without these assumptions, we know of no way to show EnKF samples correctly. For completeness, in Appendix C, we show that each ensemble member of model parameters obtained at each step of EnKF is a linear combination of the initial ensemble, which emphasizes the importance of obtaining a sufficiently large initial ensemble.
What Are Our Options for Sequestration of Atmospheric CO2—Some Thoughts
Authors: Gupta Subodh
Published: December 2007

Use of fossil fuel ever since the dawn of the industrial age has led to increased level of CO2 in the environment. Our world today is fueled mainly by fossil energy and it is unlikely that this dependence will significantly change in the near future. This coupled with the fact that majority of the developing world is at the beginning of the economic growth which is implicitly energy-intensive, the concentration of CO2 in atmosphere will only increase in the business-as-usual case.

Reduction in per capita CO2 emission both on account of minimizing explicit wastes and improving efficiencies will play a significant role in slowing down the build up of CO2. But to bring its concentration down and back to the preindustrial or comfortable levels, emphasis may have to shift to CO2 sequestration.

This paper discusses the role and potential of geological and biological sequestration approaches. Furthermore, for a longer time horizon it highlights the importance and practicality of a modified approach to bio-sequestration, where CO2 is captured and stored on surface by Carbonization of biomass through its conversion to charcoal. It highlights the fact that biosequestration can be very effective and practical but requires achievement of longer bio-storage duration which is achievable through conversion to charcoal. Also, combinations of various approaches including geological sequestration and efficiency improvement are essential to reverse the trend of increasing concentration of CO2 in the atmosphere in a short run.
Effective Matrix Acidizing in High-Temperature Environments
Authors: Aboud Ricardo , Smith Kern , Forero Leandro , Kalfayan Leonard
Published: December 2007

World demand for energy is substantial and continues to grow. By 2020, it is expected that the world will need approximately 40% more energy than today, for a total of 300 million barrels of oil-equivalent energy every day. Meeting higher energy demands will require a portfolio of energy-generation options including but not limited to oil, natural gas, coal, nuclear, steam, hydro, biomass, solar and wind.

New horizons are being explored. Wells are drilled in greater water depths. Drilling units are continually upgraded to target deeper hydrocarbon-bearing zones. Wellbore tubular metallurgy is continually upgraded. Drilling, completion and stimulation fluids are being developed for extreme temperature and pressure environments.

As the preferred technology to enhance "oilfield" energy production, well stimulation has and will continue to have an important role in fulfilling the world's future energy needs. Well stimulation generally uses fluids to create or enlarge formation flow channels, thereby overcoming low permeability, as in "tight" formations, and formation damage, which can occur in any formation type. A common and very successful stimulation option, matrix acidizing, utilizes acids that react to remove mineral phases restricting flow. Depending on the formation and acid type, flow is increased by removing pore-plugging material; or by creating new or enlarged flow paths through the natural pore system of the rock. However, higher-temperature environments present a challenge to matrix acidizing effectiveness. High temperatures can negatively affect stimulation fluid properties and certain acid reactions. Thus, careful fluid choice and treatment designs are critical to successful high-temperature matrix acidizing.

With proper fluid selection, design, and execution, matrix acidizing can be applied successfully to stimulate high-temperature oil & gas wells and geothermal wells. These types of wells have some common features, but they also have significant differences (e.g., completions, mineralogy, formation fluids and formation flow) that influence stimulation designs and fluid choices.

This paper summarizes best practices for designing matrix acidizing treatments and choosing stimulation fluids for high-temperature oil & gas wells and geothermal wells. Included are case histories from Central America. Lessons learned about differences and commonalities between stimulation practices in these well types are also discussed.
From the "What Can I Do for You" to the "What Can You Do for Me" Generation: The Disconnect Between the Establishment and the Youth Culture in the Oil Industry
Authors: LeBas Renee , Edwards W. Jason
Published: December 2007

At no point in the history of the oil and gas industry has the disparity in age between management and entry-level engineers been greater than at the present time. With the rush to hire and educate young engineers occurring at a record-setting pace, salaries are shooting through the roof and attrition is taking place at such enormous rates that companies cannot keep up. With oil and gas prices sitting near all-time highs, the ability of young professionals in the industry to dictate how they wish to move forward and with whom just increases the problems seen by companies. These young engineers often see themselves as their own enterprise within the larger corporate infrastructure and tend to ask, "What can my company do for me?"

This is in contrast to what the established management structure witnessed when they entered the industry. The majority of current managers entered the oil and gas industry during the late 1970s and early 1980s, just as the price of oil was coming to rest at its lowest point. The attitude of most of these upper-level employees is indicative of this, in that they are more prone to ask the question, "What can I do for my company?" With company loyalty quickly becoming a thing of the past, the need to understand what motivates young engineers is vital. With a thorough understanding, adjustments can be made industry-wide to make employee retention easier and more cost efficient. Several young professionals and managers in multiple companies have been interviewed to better understand the conflicting styles of the two demographics and to develop some conclusions concerning how to best move the industry forward in this new era.
Waterflood Performance by Injection of Brine With Different Salinity for Reservoir Cores
Authors: Zhang Y. , Xie X. , Morrow N. R.
Published: December 2007

Both laboratory experiments and field tests indicate that waterflooding with low salinity brine can improve oil recovery. The brine composition and the extent of dilution along with the oil phase and rock properties are all important in the process. Two consolidated reservoir cores with permeability of about 600 md were waterflooded up to 5 cycles by injection of high salinity formation brine of 29,690 ppm, low salinity brine of 1,479 ppm, and two concentrations of sodium chloride. Each core was tested with two crude oils. Either the more viscous crude oil or a viscous mineral oil was used to establish the desired initial water saturation at which mixed wettability was subsequently induced by adsorption from crude oil at reservoir temperature. Displacement tests showed that tertiary recovery from mixed wettability cores by injection of the low salinity brine was significantly higher (7 to 14% OOIP) than given by injection of the high salinity brine. Increased oil recovery was accompanied by slight change in the pH of the effluent brine and sharp increase in the pressure drop across the cores followed by slower decline. No clay was observed in the production stream and the oil/brine interface in the oil/brine separator was clear. No tertiary response occurred when the injection brine was changed to 8000 ppm NaCl solution. Further lowering to 1500 ppm NaCl resulted in 13% OOIP recovery. An additional 4% OOIP recovery was obtained by injection of low salinity brine. For a core that gave strong tertiary response, after replacement of crude oil by refined oil there was only slight recovery and small pressure response to low salinity brine flooding, even though the core was mixed wet because an adsorbed film still remained on the rock surface. Reversion to crude oil as the oil phase restored strong tertiary recovery and pressure response. A large increase in oil recovery was observed for secondary recovery by injection of low versus high salinity brine. Increase in pressure drop across the core was closely related to increase in oil recovery for both secondary and tertiary modes.
Sorption-Induced Permeability Change of Coal During Gas-Injection Processes
Authors: Lin W. , Tang G. -Q. , Kovscek A. R.
Published: December 2007

Our study has two features. First, laboratory experiments measured the change of the absolute permeability of a coal pack as a function of pore pressure and injected gas composition at constant effective stress. Second, adsorption solution theory described adsorption equilibria and aided interpretation. The gases tested include pure methane (CH4), nitrogen (N2), and carbon dioxide (CO2), as well as N2 and CO2 binary mixtures. The coal pack was initially dry and free of gas, then saturated by each test gas at a series of increasing pore pressures and a constant effective stress until steady state. Thus, the amount of adsorption varied while the effective stress was held constant. Results show that (i) permeability decreases with an increase of pore pressure at fixed injection gas composition and (ii) permeability change is a function of the injected gas composition. As the concentration of CO2 in the injection gas increases, the permeability of the coal decreases. Pure CO2 leads to the greatest permeability reduction among all the gases tested. However, a small fraction of N2, 10% to 20% by mole, helps to preserve permeability significantly. According to the mixed-gas adsorption isotherms, adsorption and the selectivity of a particular gas species for a coal surfaces is a function of pressure and the gas composition. Therefore, we conclude that loading of coal surfaces with adsorbed gas at constant effective stress causes permeability reduction. Finally, gas adsorption and permeability of coal are correlated simply to extend the usefulness of study results.
Advanced Mud Gas Logging in Combination With Wireline Formation Testing and Geochemical Fingerprinting for an Improved Understanding of Reservoir Architecture
Authors: McKinney Daniel , Flannery Matthew , Elshahawi Hani , Stankiewicz Artur , Clarke Ed , Breviere Jerome , Sharma Sachin
Published: December 2007

Understanding reservoir architecture is one of the critical factors in successful appraisal and development of any oil/gas field. Increasing drilling costs and environmental challenges has led to the development of alternative appraisal approaches that compliment the more costly and traditional methods such as the drill stem or production test. Therefore, the challenge of obtaining sufficient reservoir and fluid data from complex wells, in short time frames and at manageable costs, has pushed game changing improvements to both mud logging and wire line testing technologies.

In the past, interpretation of wireline formation testing data (e.g., static pressure gradient analysis and downhole fluid analyses), PVT and geochemical fingerprinting have provided major inputs for reservoir modeling related to reservoir continuity. However, none of these tools or data sets provide hydrocarbon distributions or fingerprints during the drilling process of a given well; only after the well has reached final depth and LWD and e-logs have been obtained can one begin to speculate on such matters as reservoir continuity. Until recently, standard mud gas logging technologies did not offer the resolution and sensitivity necessary to provide quantitative hydrocarbon description. However, recent developments in advanced mud gas extractors and improved analytical detectors have increased the sensitivity, reliability and accuracy of mud gas fingerprinting. Thus, during the drilling of a given well, mud gas fluid fingerprints, or fluid facies, can be correlated within a given well and mapped to subsurface structural features such as faults and seals or different hydrocarbon bearing intervals. By providing this during the drilling process, anomalies observed in these fluid facies logs can be investigated in more detail during formation evaluation, sample collection, and geochemical fingerprinting techniques. In addition, by systematically combining and integrating these fundamentally different data streams, a much more robust picture of the reservoir fluid distribution becomes clear.
Advanced Technology Completion Strategies for Marginal Tight Gas Sand Reservoirs: A Production Optimization Case Study in South Texas
Authors: Fairhurst D. L. , Indriati S. , Reynolds B. W. , Lewis J. W. , Holcomb M. W. , Starr F. F.
Published: December 2007

In this case study we address the problems associated with fracturing tight gas sands when nearby water sands are present. Often times the problem is that the created fracture might intersect the water sands which can impede the gas production and in extreme cases can kill the well. Production forecasts based on calibrated permeability values can be performed to show the impact of water production to gas production. If the production forecast indicates that there is enough gas to unload and carry the water to surface then an optimized larger fracture treatment based on effective and relative permeabilities can be performed across both gas and water intervals. If there is not enough gas present to unload the water then the fracture treatment must be carefully designed such that the fracture length is still optimized and water penetration does not occur.

A process is described to optimize completion and stimulation design decisions while reducing uncertainty. Production forecasts are made based on a petrophysically advanced reservoir characterization and stimulation design based on a rock mechanical model adjusted for thin laminations. The actual production results have been compared with the forecasts and the process has been calibrated. These calibrations have led to improved economic results in the field. This production optimization process will apply where there are stacked and laminated tight gas sand sequences in close proximity to water sands. Field production can be increased by fracturing gas sands that are normally thought to be too close to water sands as well as gas sands with high interstitial water that would normally be bypassed. Within this case study, several wells were completed that produced a mixture of gas and water which normally would have been plugged or bypassed. Some wells produced more water than predicted and were not economical. Two wells were completed within 20 ft of obvious water sand by adjusting the job size and water was avoided completely. Six wells were stimulated within 30 ft of water and resulted in economical gas and negligible water production. The combination of magnetic resonance acquired permeability estimates and rock mechanical models adjusted by image enhanced petrophysics provided effective input to modify the stimulation design and enable economic completions for gas sands that were very close to stacked water sands.

Around the world, strands of tight natural gas resource lie unproduced next to and within water bearing sands. The production optimization process that is described combines several completion techniques that incorporate currently available technology to give the completion engineer one more tool to gain access to these reserves. This technique is not geographically limited and applies to any tight gas sand resource.
Pore-Level Analysis of the Relationship Between Porosity, Irreducible Water Saturation, and Permeability of Clastic Rocks
Authors: Torskaya T. , Jin G. , Torres-Verdín C.
Published: December 2007

Permeability is one of the most important, most spatially variable, most uncertain, and hence least predictable transport properties of porous media. Various empirical models, such as Tixier's, Timur's and Coates’ equations, are widely used to quantify permeability from well-log calculations of porosity and irreducible water saturation. However, these models do not explicitly include the role played by rock structure, spatial fluid distribution in the pore space, wettability, or clay mineral distribution on permeability. We present a pore-scale approach to investigate the influence of these factors on the permeability of clastic rocks for explicit pore geometries of brine-saturated granular rocks.

Synthetic pore-scale models are constructed to represent granular sands with variable grain-size distributions. These models include the structural effects of compaction, cementation, and distribution of dispersed hydrated clay minerals. Irreducible water is geometrically distributed on grain surfaces of the synthetic rocks. Permeability is calculated from lattice-Boltzmann flow simulations. A nonlinear relationship between permeability, porosity, and irreducible water saturation is established for these computer-generated rocks. We compare calculated permeability values of computer-generated rocks and laboratory measurements of core samples to those estimated from different empirical approaches, such as Tixier, Coates, and Timur models. It is found that the latter models cannot be applied to general cases of clastic rocks even if their free parameters are adjusted to fit core measurements. Our simulations also show that spatial distributions of clay minerals and irreducible water play a fundamental role in establishing an accurate correlation between permeability, porosity, and irreducible water saturation. Specific deterministic equations must be established for rock formations that exhibit distinct grain-size distributions, clay types, structural clay distributions, and grain cementation.
Estimation of Dry-Rock Elastic Moduli Based on the Simulation of Mud-Filtrate Invasion Effects on Borehole Acoustic Logs
Authors: Odumosu Tobiloluwa , Torres-Verdín Carlos , Salazar Jesùs M. , Ma Jun , Voss Ben , Wang Gong Li
Published: December 2007

Reliable estimates of dry-rock elastic properties are critical to accurately interpreting the seismic response of hydrocarbon reservoirs. We describe a new method for estimating elastic moduli of rocks in-situ by simulating the effect of mud-filtrate invasion on resistivity and acoustic logs.

Simulations of mud-filtrate invasion account for the dynamic process of fluid displacement and mixing between mud-filtrate and hydrocarbons. The calculated spatial distributions of electrical resistivity are matched against resistivity logs by adjusting the underlying petrophysical properties. We then perform Biot-Gassmann fluid substitution on the two-dimensional spatial distributions of fluid saturation with initial estimates of dry-bulk (kdry) modulus and shear rigidity (μdry) and a constraint of Poisson's ratio (v) typical of the formation. This process generates two-dimensional spatial distributions of compressional and shear-wave velocities, and density. Subsequently, sonic waveforms are simulated to calculate shear-wave slowness. Initial estimates of the dry-bulk modulus are progressively adjusted using a modified Gregory-Pickett (1963) solution to Biot's (1956) equation to estimate a shear rigidity that converges on the log value of shear-wave slowness. The constraint on Poisson's ratio is then removed and a refined estimate of the dry-bulk modulus is obtained by both simulating the acoustic log (monopole) and matching the log-derived compressional-wave slowness.

This technique leads to reliable estimates of dry-bulk moduli and shear rigidity that compare well to laboratory core measurements. The resulting dry-rock elastic properties can be used to calculate seismic compressional-wave and shear-wave velocities devoid of mud-filtrate invasion effects for further seismic-driven reservoir-characterization studies.
Mad Dog Slot W1 Tubing Deformation Failure Analysis
Authors: Pattillo P. D. , Sathuvalli U. B. , Rahman S. M. , Prewett H. H. , Carmichael S. P. , Wydrinski R.
Published: December 2007

On 20Apr05, while bringing Mad Dog Slot W1 back on production after a brief shut-in, pressure developed on the A annulus and persisted despite repeated bleeds. Diagnostic pressure tests and logs eliminated a number of possible sources of the annulus pressure, eventually leading to the conclusion that the 9-7/8 in. production tieback had been breached. Further investigative logs led to the observation of ovalization of the production tubing.

This study summarizes the efforts of the team assigned to investigate the causes of the production tubing and casing deformation. The outcome of the analysis suggests a subtle failure mode, ultimately related to attempts at annular pressure build-up mitigation. The subtlety emphasizes the importance of (a) design considerations in uncemented annuli opposite salt, (b) the importance of creating a complete cement sheath and (c) the inherent difficulties in converting an appraisal well into a producing well.

The study concludes with a brief review of the changes implemented in the replacement well intended to eliminate a repeat of the identified failure mechanism(s).
Near-Wellbore Modeling: Sand Production Issues
Authors: Servant Guillaume , Marchina Philippe , Nauroy Jean-François
Published: December 2007

Sand production in an oil or gas well can cause additional operational difficulties, but contributes to production enhancement by improving the well inflow performance. In order to be able to assess the relatve magnitude of those two effects and to optimize the well completion and operation philosophy, a quantitative forecast of the expected amount and rate of sand production must be established. It requires a correct description of all the mechanisms involved in the phenomenon of sand production, sand transport in particular.

The proposed numerical method considers that the geomechanical problem (rock failure) interplays with the transport of sand. Equilibrium equations which control rock failure (solid mechanics) and sand transport (fluid mechanics) are solved simultaneously by an iterative coupled scheme at the wellbore scale.

Sand production experiments in the laboratory on cohesionless sand samples carried out under CT-scan are used to calibrate the model and show its ability to reproduce the main sand production features.

The results of this fully coupled scheme show the importance of the transport of sand within the reservoir, in particular the effect of a non homogeneous slurry viscosity, for a proper modeling of the sand production process.
Characterization of Arab Formation Carbonates Utilizing Real-Time Formation Pressure and Mobility Data
Authors: Seifert Douglas J. , Neumann Peter M. , Dossary Saleh M. , Chew Kuen Kong , Hahne Ulrich , Bacciarelli Mark , Pragt Jos
Published: December 2007

Wireline logging formation testing tools have long been used in the Arabian Peninsula for open hole formation pressure testing.Presently, a large number of wells are being drilled horizontally as producers and injectors, and often even as multilateral wells. This aggravates or prevents the use of conventional wireline logging technology. Formation pressure data are required to monitor the efficiency of production and injection for pressure maintenance.

The Arab formation is a very prolific producing formation that consists of several members deposited in a carbonate shelf environment. Besides formation pressure, a representative permeability is an important element of the data acquisition. The Arab formation porosity and permeability are variable and dependant on original facies, mineralogy and diagenesis. Highly porous rock can have variable permeability dependant on a number of these factors.

Conventional logs can show zones to be porous and hydrocarbon filled. These zones can be difficult to produce or inject due the presence of viscous heavy oil and tar. Therefore complicating the geosteering of the horizontal producers and injections. It has been found that the best way of recognizing such zones reliably, is through the utilization of real-time formation pressure testing data while drilling, preferably combined with magnetic resonance data.

This paper will discuss examples of carbonate reservoir characterization utilizing formation pressure testing in combination with a full LWD logging suite. Operating procedures were specifically optimized to allow quality control of each acquired data set. An extensive, highly detailed, data set was transmitted to the end user, displayed real time both on the rig-site as well as in the operator datacenter to properly place the horizontal well for its intended objective.
Complex Fracture Geometry Investigations Conducted on Western-Siberian Oil Fields at Rosneft Company
Authors: Nikitin A. , Shirnen A. , Maniere J.
Published: December 2007

The generalization of Hydraulic fracturing in West Siberia and the increase of job size over the recent year can impact the field development strategy. The correct estimation of the fracture dimension is critical to maximize the recovery factor of heterogeneous reservoir developed with water flood. Three main uncertainties exist: fracture height, half-length and azimuth. Commercial fracture models provide length estimate once a reliable estimate of height is known. This is evident for 2D model which requires a direct knowledge of the height but also for p3D model where the height is indirectly obtained from coupling stress profile and fluid flow. Fracture azimuth is traditionally provided by the horizontal stress anisotropy from open hole sonic logging. Unfortunately, in West Siberia at depth of 2500-3000 meters, there is negligible tectonic and open hole sonic dipole did not provide obvious fracture orientation. Fracture height growth affect mostly fracture job size and cost. Height growth has also shown to be a cause of premature wellbore screen out. Fracture half-length and orientation can have a significant impact on the effectiveness of pressure maintenance and flood efficiency. A review of world publication of direct fracture geometry measurement has shown the validity of seismic methods and tilt indicators for tight rock, such as carbonates and tight sandstone. However, all experiments on soft sandstones, such as found in West Siberian, have shown more limited results.

Given the uncertainties in effective Fracture geometry and the negative impact that they could have on the field development, Rosneft decided to invest in a field research study denominated Fracture Geometry Investigation, to validate various method offered by the service industry. Two basic methods were tested and combined: wellbore logging and passive seismic. Wellbore logging is used to obtain an estimate of wellbore fracture height. It combines temperature log immediately after Minifrac or after Frac and Cased Hole Sonic Anisotropy (CHSA) which can be run at any time after frac. The direct estimate of fracture height is used to validate the result of a calibrated HF simulator using Net Pressure matching analysis. Passive Seismic monitoring (PSM) is used to obtain direct estimate of height, length and azimuth. PSM Acquisition must be done during hydraulic fracturing from the nearest well.

The main goal of this study was to validate each method's effectiveness and to construct a calibrated fracture model for the particular reservoir under investigation. The results of this investigation will be used to optimize fracture design, pressure maintenance strategy and pattern orientation.
An Alternative Solution to Sandstone Acidizing Using a Nonacid-Based Fluid System with Fines-Migration Control
Authors: Rozo Rafael , Paez Javier , Mendoza Alberto , Milne Arthur , Soler Diego , Abuseif Hussam
Published: December 2007

The Caballos formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy. However, the production from this formation is often limited due to the low critical flow rate in the matrix (less than 1 mL/min) and associated fines migration as shown in several tests.

Historically matrix acidizing and hydraulic fracturing treatments in this formation have only been partially successful due to destabilization of the clays and inadequate fines stabilization, along with the incompatibility of the crude oil with many conventional acid systems.

In order to overcome the limitations associated with the use of conventional acid systems an extensive laboratory study was conducted using a non-acid based stimulation fluid. The base fluid selected was a newly developed chelating agent that is very tolerant to high concentrations of both carbonate and aluminosilicates, and iron and zeolite bearing minerals. By including acid salts in the fluid it proved possible to develop a fluid system with the equivalent dissolving power of a conventional 6:1.5 (HCl: HF) mud acid, even at temperatures as low as 180°F. Testing also showed that the fluid was capable of controlling fines migration and that a scale inhibitor could be included in the formulation, while the fluid system exhibited excellent compatibility with the formation fluids throughout the field.

The newly developed non-acid fluid system provides some unique advantages for matrix acidizing applications and in particular for stimulating the Caballos formation 1) Minimizes the risk of secondary and tertiary precipitation due to the nature of the chelating agent 2) A single treating fluid instead of the multiple fluids/stages used in a conventional treatment 3) Greatly reduced sludging and emulsion tendencies compared to conventional acid systems (without the addition of surfactants or demulsifiers) and much lower corrosion rates 4) The ability to stabilize fines present in the matrix 5) Allows for a scale inhibitor to be included in the treating fluid 6) Reduces the logistics and HSE risks during the execution of the treatment.

This paper reviews the laboratory testing including an extensive core flow testing performed to develop a new nonacid treating fluid for both matrix acidizing and dual stimulation applications in the Caballos formation and its implementation in the field, illustrated with case studies and production data.
Matching of Production History and 4D Seismic Data—Application to the Girassol Field, Offshore Angola
Authors: Roggero F. , Ding D. Y. , Berthet P. , Lerat O. , Cap J. , Schreiber P. E.
Published: December 2007

This paper presents an advanced history matching methodology for constraining 3D stochastic reservoir models to both production history and 4D seismic attributes. The proposed approach is based on an optimization loop which integrates geostatistical modeling, upscaling, fluid flow simulation and petro-elastic modeling in the same workflow. Simulated production history and 4D seismic attributes are compared to real data using a single objective function, which is minimized using a new optimization algorithm based on response surface fitting.

Inversion parameters can be selected throughout the entire modeling workflow, to update the facies spatial distribution, the petrophysical properties and fluid flow parameters. Advanced parameterization techniques are used to constrain the fine scale geostatistical model. The gradual deformation method allows smooth transformations of the facies model realization while conserving the overall statistical characteristics. In addition, a new history matching technique has been implemented to constrain the average facies proportions over given regions. As an example, new geologically-based parameters like shale proportions in flow barriers or sand proportions in channel sequences can be considered in the inversion process.

A successful application to the Girassol field is presented. Girassol is a large, complex and faulted turbidite field located offshore Angola. A detailed geostatistical model was built first from 3D high resolution seismic data. The major challenge was to integrate 4D seismic data to constrain the reservoir model in a quantitative way.

The gradual deformation method has shown a major impact on production history, since the changes in the facies distribution affect the connectivity in sandy channels and the position of shaly barriers. A good match of water and gas breakthrough was obtained over one year of production data. The addition of new geological constraints allowed us to better honor the 4D seismic information (extent of gas injection and of depleted zones). This was achieved by constraining average sand and shale proportions over channel and levee regions. Improved predictions of future production and of a new seismic survey have been obtained using the matched model.
An LWD Tool Suite for Formation Evaluation in HP/HT Environments
Authors: Rennie A. , Boonen P.
Published: December 2007

The tool suite that is introduced in this paper provides Logging-While-Drilling (LWD) formation evaluation with tools rated up to 350°F (175°C) and 25,000 psi (172.4 MPa). These ratings qualify as High Pressure High Temperature (HPHT) environments for LWD services, where the standard ratings are much lower. The HPHT LWD suite consists of measurement-while-drilling (MWD), annular pressure, resistivity and nuclear porosity services.

The MWD service provides surveys, optional gamma ray measurements and the mud-pulse telemetry connectivity to the surface. Changes to the real-time pulsed telemetry data streams can be requested from the MWD surface system to accommodate customer requirements for any sections logged within the wellbore. A retrievable MWD system is also available for high-risk drilling environments and conditions. The quartz pressure tool measures annular pressure, drill pipe pressure and mud temperature.

The resistivity service comprises of a dual frequency (2MHz and 500 kHz) borehole compensated wave propagation tool with three transmitter-to-receiver coil spacings. The combination of dual frequency, triple transmitter coils and phase/attenuation measurements provides twelve resistivity curves with different diameters of investigation. Advanced resistivity analysis compute six dielectric assumption independent resistivities, and the related dielectric constants. In anisotropic formations in high angle wells, the horizontal and vertical resistivities are calculated.

The porosity service is a density-neutron-stand-off-caliper tool. The spectral bulk density (Rhob) measurement is compensated for stand-off. Three neutron porosities are computed from the three neutron detectors. The more environmentally friendly Californium252 source emits a neutron output comparable with a conventional LWD Americium-Beryllium source but at a much lower radioactivity. The source is recyclable, thus removing the need for quasi-eternal storage for depleted sources.

The tools in this suite are modular and can be configured in any order. A selection of Bottom Hole Assemblies (BHA) will be shown. Examples will show the range of measurements and the advanced applications.