bluuebunny/crossref_metadata_2025 huggingface dataset:
Updated United Nations Framework Classification for Reserves and Resources of Extractive Industries
Authors: Ahlbrandt Thomas S. , Blaise Jean René , Blystad Per , Kelter Dietmar , Gabrielyants Gregorio , Heiberg Sigurd , Martinéz Anibal , Ross James G. , Slavov Slav , Subelj Andrei , Young Elliott D.
Published: December 2007

The United Nations have studied how the oil and gas resource classification developed jointly by the SPE, the World Petroleum Congress (WPC) and the American Association of Petroleum Geologists (AAPG) could be harmonized with the United Nations Framework Classification (UNFC) for Solid Fuel and Mineral Resources (1).

The United Nations has continued to build on this and other works, with support from many relevant international organizations, with the objective of updating the UNFC to apply to the extractive industries. The result is the United Nations Framework Classification for Energy and Mineral Resources (2) that this paper will present.

Reserves and resources are categorized with respect to three sets of criteria: Economic and commercial viabilityField project status and feasibilityThe level of geologic knowledge

The field project status criteria are readily recognized as the ones highlighted in the SPE/WPC/AAPG classification system of 2000. The geologic criteria absorb the rich traditions that form the primary basis for the Russian classification system, and the ones used to delimit, in part, proved reserves. Economic and commercial criteria facilitate the use of the classification in general, and reflect the commercial considerations used to delimit proved reserves in particular.

The classification system will help to develop a common understanding of reserves and resources for all the extractive industries and will assist: International and national resources management to secure supplies;Industries' management of business processes to achieve efficiency in exploration and production; andAn appropriate basis for documenting the value of reserves and resources in financial statements.
Use of Stripping Ratios to Identify Dispersion Levels and Displacement Mechanisms in Miscible Gas Floods
Authors: Parakh Harshad , Johns Russell T.
Published: December 2007

Oil recovery estimated from numerical simulation of miscible gas floods is highly dependent on the grid-block sizes used and the level of reservoir dispersion. Stripping ratios, defined as the ratio of certain heavy to light components, have been used recently to estimate the level of in situ dispersion at the field scale. The use of stripping ratios, however, has not been thoroughly investigated.

The focus of this paper is to validate the use of stripping ratios and to determine its appropriate definition for certain gas injection processes. The approach is applied to the condensing/vaporizing displacement of twelve-component oil by a five-component miscible injectant (MI). Analytical gas injection theory based on the method of characteristics is used to help identify the correct choice of components to calculate the stripping ratio. Numerical simulations are conducted for both 1-D and 2-D gas floods.

The results from 1-D displacements show that the condensing and vaporizing region can be identified from stripping ratios when the stripping ratio is calculated from the heaviest component in the oil and the lightest component in the oil not present in the injected gas. The stripping ratio for 1-D field scale displacements is shown to be useful in identifying (as measured from core data) if a large level of dispersion and mixing is present for such reservoirs. For more realistic 2-D (and 3-D) displacements, however, crossflow or re-saturation occurs, which can complicate the interpretation of the stripping ratio and its use as a practical reservoir engineering tool. We show that the level of dispersion at field scale might be qualitatively confirmed by comparison of stripping ratio and oil saturation data from cores to those determined from simulation. When dispersion is low (near a longitudinal dispersivity of about 1.0 ft) resaturated regions give large oil saturations accompanied by very large stripping ratios. These features are not present at dispersivity levels greater than 5.0 ft.
Rotary Sidewall Cores- A Cost Effective Means of Determining Young's Modulus
Authors: Britt Larry K. , Smith Michael B. , Haddad Ziad , Reese Jennifer , Kelly Patrick
Published: December 2007

The objective of hydraulic fracturing is to design and execute a fracture stimulation treatment that achieves the desired fracture dimensions (length and conductivity) to maximize a wells production rate and reserve recovery. To achieve this objective, there are several critical parameters to the process, and these fall into two distinct categories: 1) parameters over which we have little control, but need to understand, and 2) those that we control, but have lesser impact on the process. The first category includes fracture height, fluid loss coefficient, tip effects, and Young's modulus. The second category includes pump rate and fluid viscosity. Of the former parameters, Young's Modulus is the only variable that can be measured, in advance, via lab tests.

Traditionally, Young's Modulus is measured through stress-strain testing of geologic samples (core plugs) which always demanded an L/d (Length/ diameter) ration of at least 2:1. The reason for this criterion is that the ultimate failure mechanism for most rocks under compression loads is the formation of a shear fracture. For most rock types, this shear fracture will form at an angle of about 30° from the axis of the maximum compression load. Thus, a 2:1 L/d ratio allows a through-going shear fracture to form for a failure angle of 30°. For stress-strain testing NOT concerned with ultimate failure of the sample, this valid criterion has always been followed - arbitrarily and artificially. Unfortunately, this sample criterion generally eliminates the use of sidewall cores.

This paper details and documents an evaluation of the Length to diameter criteria through finite element modeling, tri-axial compression testing of aluminum, and compression testing of actual sedimentary rock samples. Through this work, it is evident that core samples of L/d significantly less than 2:1 can provide reliable values of static Young's Modulus. Further, these results indicate that rotary sidewall cores can be utilized to determine Young's Modulus in many applications provided adequate sample quality assurance is undertaken to ensure sample integrity.
Simulation of Miscible Flow Including Bypassed Oil and Dispersion Control
Authors: Coats K. H. , Thomas L. K. , Pierson R. G.
Published: December 2007

This paper describes methods for the simulation of first contact miscible, multi-contact miscible and vaporizing gas drive, which include logic to account for bypassed oil. Dispersion control is included for first contact miscible, FCM, cases.

First contact miscibility may be simulated in fully compositional mode or in pseudo two-component EOS mode. Pseudoization is performed internally in the model so that hydrocarbon fluid density and viscosity, as functions of pressure and composition, are the same as calculated in NC-component mode. Bypassed oil and dispersion control are based on an extension of Koval's method. This procedure allows the user to adjust the fractional flow of oil during upscaling or history matching to match fine grid or historical results. This feature can be used to simulate both WAG and tertiary recovery projects where solvent injection is preceded by a water injection period.

Example cases are included to illustrate the techniques presented in this paper. Results are also given on the efficiencies of the algorithms.
Improved Pore-Pressure Prediction and Mechanical Earth Model Estimation Through Binary Decomposition of Seismic Inversion Data in Subresolution Clastic Sequences
Authors: Engelmark Folke
Published: December 2007

Formation pore pressures that exceed the hydrostatic gradient are common in all basins worldwide. The most common cause is undercompaction, which occurs when the rate of shale sedimentation is high, thus preventing water to escape from the pore space in the underlying sediments. This leads, in turn, to a redistribution of the overburden stress, i.e., part of the overburden stress is maintained by the pore fluids and the effective stress on the rock fabric decreases by an equal amount. Porosity is preserved and assumed to be in balance with the effective stress. Other mechanisms that can generate increased pore pressure include: dewatering of clays, generation of hydrocarbons, cracking of oil to gas under increasing temperature, and volumetric increase of the fluids when temperature is increasing.

Uncertainty in the pore-pressure profile along the planned drilling path means, at the very least, increased cost to cover contingency plans, but can also include very expensive mitigation work, especially in deep- and ultra-deepwater environments. Worst-case scenarios can include loss of the well, loss of lives, and severe environmental impact.

Current state-of-the-art methods for pore-pressure prediction include classification of lithology and pore fluids based on prestack inverted data yielding compressional and shear velocities as well as density. This allows the rock physics equations to be customized for improved accuracy in the predicted pore pressure.

Clastic basins consist predominantly of interbedded shales and sands. The vertical resolution of seismic data depends on the wavelength of the propagating seismic energy, but typical resolution in Tertiary basins is about 30 ft, which means the extracted elastic parameters often represent a net to gross (N/G) rather than the properties of individual sands and shales. The volumetric content of each lithology can be evaluated from the elastic parameters extracted from the seismic data. However, when there are hydrocarbons present, especially gas, the estimate of N/G and the elastic properties of the two lithologies are more difficult to evaluate.

In this paper, we take the inversion process one step further by decomposing the seismic elastic data into the individual properties of the sands and shales. In addition to improving the accuracy of the pore-pressure prediction and the mechanical properties of the two lithologies, we also get an estimate of N/G, hydrocarbon properties, and saturation in the sands. The ability to estimate elastic properties for sands and shales individually is also very important to get correct estimates of the mechanical rock properties.
Insitu Characterization of Formation Fluid Samples - Case Studies
Authors: Elshahawi H. , Hashem M. , Dong C. , Hegeman P. , Mullins O. C. , Fujisawa G. , Betancourt S.
Published: December 2007

Sampling in the early stages of the exploration and development cycle is essential to provide key information for field planning and facilities design. In the majority of deepwater and other high cost wells drilled these days, formation tester samples may be the only source of fluid properties reliable enough to be used for economic screening. It is therefore critical to collect representative high quality samples early in any exploration or appraisal campaign. With the aid of real time insitu fluid characterization, sample quality can be assured, and the sampling process can be optimized. Insitu fluid characterization is essential for making decisions about where and when to sample, and how many samples to acquire. In that manner, maximum quality information may be acquired in an optimal amount of time. This is particularly critical in offshore deepwater sampling jobs, where rig rates can reach hundreds of thousands of dollars per day.

This paper describes how the latest techniques for downhole fluid characterization can be put to maximum use. These techniques include real time composition measurement, fluid type identification and single-phase assurance. The absorption properties of hydrocarbons in Near-Infrared spectroscopy and principal component analysis techniques are used to obtain real time composition. This includes carbon dioxide concentration, Gas-Oil-Ratio, and water volume fraction as well as the relative abundance of three broad reservoir fluid pseudo-components. Fluid type identification and single-phase assurance are achieved with downhole gas detection and fluorescence measurements. Fluorescence monitoring enables the detection of condensate formation if the dew point pressure of a wet or retrograde gas system is crossed during sampling. In some cases, it also provides a means of qualitatively distinguishing between gas, condensate, light oil, and heavy oil from oil-base-mud filtrate.

Several case studies are presented here to demonstrate the techniques of composition measurement, fluid type identification, and single-phase assurance. The case studies clearly show how these techniques help obtain high quality sample in an optimal amount of time.
Dynamic Simulations With an Improved Model for Foam Generation
Authors: Kam S. I. , Nguyen Q. P. , Li Q. , Rossen W. R.
Published: December 2007

We present the first 1D simulations of dynamic foam displacements with a new population-balance model incorporating bubble creation controlled by pressure gradient. For the first time, a population-balance model is fit to steady-state experimental data for both the three foam states (coarse foam, intermediate state, and strong foam) and the two strong-foam regimes (low-quality and high-quality) observed in laboratory studies. Simulations confirm the stability of the coarse-foam and strong-foam states to small perturbations, and the instability of the intermediate state.

In dynamic displacements, the model shows foam generation as injection rates increase, or as liquid fraction of injected fluids increases, in agreement with laboratory observations.

When coarse foam is created instead of strong foam, there is a narrow region of finer foam predicted near the gas displacement front. This region appears to play a role in foam generation. However, in the cases examined, foam generation occurs at roughly the same injection rate as predicted by local-steady-state theory. Because of this narrow region of finer-textured foam, fronts can be sharper than estimated from fractional-flow theory assuming a constant gas viscosity at its steady-state value behind the displacement front.

If a strong foam forms in the low-quality-regime, the kinetics of foam generation and destruction affect the length of the entrance region in which foam forms. Therefore, the length of the entrance region can be used to calibrate the kinetic parameters in the model. The displacement front and the bank behind it, however, are essentially what one would have predicted from local-steady-state modeling. The complexities of population-balance modeling are not necessary, if it is known that strong foam will be created.
Injection Wells: A Case Study From the Statfjord Field
Authors: Andrews J. , Hettema M. , Nesse T.
Published: December 2007

The Statfjord oil field, operated by Statoil in the North Sea, has been on production since 1979. The reservoir management strategy has been water flooding and secondary recovery mechanisms involving gas injection. To date over 63% of the STOOIP has been recovered.

Good injector performance has been instrumental in the economic development of the Statfjord field. The purpose of this study is to investigate injectivity trends in the injection wells in order to understand the processes that influence initial and long term injectivity. This includes thermal fracturing of water injectors and a comparison of injectivity in Water-alternating-gas (WAG) wells during the various cycles of gas and water injection. The Statfjord production database contains large amounts of data for these wells including injection rates and pressures, injection profiles from production logging, and various static pressure measurements.

Fracturing during water injection is found to result in folds of increase in injectivity of between 2 and 4. Whilst the resulting improvements in injection rates have been advantageous for pressure maintenance, out of zone fracturing in some wells has been detrimental to the efficient sweeping of some sand members. Gas injection on Statfjord is shown to be governed by matrix flow and fractures from previous water injection cycles do not stay open during subsequent gas injection in the WAG wells.
Optimization of Commingled Production using Infinitely Variable Inflow Control Valves
Authors: Naus M. M. J. J. , Dolle N. , Jansen J. D.
Published: December 2007

We developed an operational strategy for commingled production with infinitely variable Inflow Control Valves (ICVs) using sequential linear programming. The optimization algorithm requires instantaneous and derivative information. We propose a workflow where the production engineer relies on measurements to determine the flow rate and pressure values, and on models to determine the derivative information, i.e. the changes in flow rates as a result of a change in an ICV setting. Such a model would typically be a steady-state well bore simulator including choke models to represent the ICVs and inflow models to represent the near-well reservoir flow in the various zones. The parameters of the model need to be updated regularly using real-time measurements and production tests, and we discuss the impact of different smart well instrumentation levels on the updating process.

We simulated the performance of this production optimization strategy in a reservoir simulator. Some numerical aspects of the algorithm and problems encountered during implementation are discussed. The performance of the algorithm was tested in two reservoir settings. In both cases, the optimization resulted in accelerated oil production compared to conventional, surface controlled, production. However, accelerated production did not always result in higher ultimate recovery compared to the conventional case. In such situations the benefits of either short-term production optimization (accelerating production) or long-term reservoir management (maximizing recovery) should be weighed.
Simultaneous Estimation of In-Situ Multi-Phase Petrophysical Properties of Rock Formations from Wireline Formation Tester and Induction Logging Measurements
Authors: Alpak Faruk O. , Torres-Verdín Carlos , Habashy Tarek M. , Sepehrnoori Kamy
Published: December 2007

We introduce a novel inversion algorithm for the in-situ petrophysical evaluation of hydrocarbon-bearing formations The algorithm simultaneously honors a set of multi-physics data: (a) Pressure-transient, flowline fractional flow, and salt production rate measurements as a function of time acquired with a wireline-conveyed, dual-packer formation tester, and (b) borehole array electromagnetic induction measurements. Both time evolution and spatial distribution of fluid saturation and salt concentration in the near-borehole region are constrained by the physics of mud-filtrate invasion. The inverse problem consists of the simultaneous estimation of a two-dimensional axisymmetric spatial distribution of absolute permeability and parametric saturation functions for relative permeability and capillary pressure curves. For a given layer, both horizontal and vertical permeabilities are subject to inversion. Saturation functions of relative permeability and capillary pressure are parametrically represented using a modified Brooks-Corey model.

We simulate numerically the response of borehole logging instruments by reproducing the multi-phase, multi-component flow that takes place during mud-filtrate invasion and formation test. A fully implicit finite-difference black-oil reservoir simulator with brine tracking extension is used to simulate fluid-flow phenomena. Electromagnetic-induction measurements are coupled to the physics of fluid flow using a rapid integro-differential algorithm. Inversion experiments consider both noise-free and noise-contaminated synthetic data. Joint inversion results provide a quantitative proof-of-concept for the simultaneous estimation of transversely anisotropic spatial distributions of permeability and saturation-dependent functions. The stability and reliability of the inversions are conditioned by the accuracy of the a priori information about the spatial distribution of formation porosity and fluid PVT properties. For cases where multi-physics measurements lack the degrees of freedom necessary to accurately estimate all the petrophysical model parameters, we develop an alternative sequential inversion technique. The first step involves estimation of horizontal and vertical permeabilities from late-time transient-pressure measurements. Subsequently, the entire set of measurements is jointly inverted to yield saturation-dependent functions.
Rapid Scenario and Risk Analysis for a Complex Gas Field with Large Uncertainties
Authors: Hegstad B. K. , Tollefsen S. , Arghir D. V. , Cullick A. S. , Narayanan K. , Heath D. E. , Lever J. C.
Published: December 2007

Increasingly, the industry is aware of the need to improve field development planning decisions with more rigorous risk analysis. A key is to have technology and work processes supporting the complex evaluation of projects as a whole, i.e. from subsurface to processing with economics, while preserving physical fidelity and interdependent uncertainties. This paper will illustrate how an integrated stochastic approach with scenario analysis, sensitivity analysis, and Monte Carlo simulation assisted an asset team to understand overall project uncertainties and sensitivities for a large gas project. This understanding gave a better basis for the planning decisions.

The richness and speed of the integrated stochastic approach is compared with more conventional case study analysis. The latter requires manual iteration to investigate how variations of input variables as e.g. reservoir properties impact reserves and production. It is followed by manual input to the economic model and manual analysis.

Outputs presented from hundreds of simulations from the integrated stoachastic approach include distributions and histograms of original fluids in place, cumulative production, plateau period, net present value, production rate, discounted cash flows, and rates of return etc. Correlation coefficients between input uncertainties and output uncertainites indicate which input uncertainties give the major contribution to the output uncertainties. This helps the asset team to focus on the important factors for major decisions, and use less time on the less important issues.
Impact of Induced Fractures on Sweep and Reservoir Management in Pattern Floods
Authors: van den Hoek P. J.
Published: December 2007

It is well established within the Industry that water injection almost always takes place under fracturing conditions. Particularly when large quantities of very contaminated water are injected –either for voidage replacement or disposal- large fractures may be induced over time.

This paper presents the results of a study addressing the impact of induced fractures on the "present value" recovery and on the reservoir management in pattern waterfloods. The background of this study is that there exists a general perception that long fractures have a negative impact on recovery. However, this perception is largely based on past studies where only attention was given to recovery as a function of pore volumes injected, not time. In addition, the impact of injection water contamination was never addressed.

Based on streamline simulations on two types of patterns (five-spot and nine-spot), in which the fracture lengths and orientations, in addition to the fluid mobility ratios, were varied, it is concluded that induced fractures in pattern floods generally result in a significant recovery improvement, even for cases in which the induced fractures are "long" (i.e. exceeding roughly 25% of the pattern unit cell size).

In the nine-spot pattern, induced fractures result in by far the largest recovery improvement. It is shown that in this case, the recovery for fractured injection is still significantly above that for matrix injection even when the induced fracture closely approaches one of the producer wells in the pattern unit cell. Furthermore, it is shown that for sufficiently long fractures, the impact of contamination of the injection water on recovery generally is very limited.

Finally, it is demonstrated that depending on pattern type, fracture orientation, and injection water contamination, there exists an optimum induced fracture length that maximizes recovery. This optimum induced fracture length corresponds to that specific injection rate that yields a maximum oil production rate. Because of changing average reservoir fluid mobility over time, this optimum fracture length can only be maintained if injection rates change over the field life. An optimum reservoir management policy should attempt to maintain the induced fracture at its optimum length over the field life by appropriate adjustment of injection rates.
Fluid Sampling and Interpretation with the Downhole NMR Fluid Analyzer
Authors: Akkurt Ridvan , Fransson Carl-Magnus , Witkowsky James M. , Langley William M. , Sun Boqin , McCarty Andrew
Published: December 2007

One of the main applications of MRILab, the recently introduced NMR fluid analyzer, is the estimation of mud-filtrate contamination during the pump-out phase, prior to securing high quality fluid samples for PVT analysis. The NMR fluid analyzer utilizes T1 saturation recovery measurements for contamination analysis. The main objective of this paper is to discuss the principles behind recently developed T1-based novel methodologies that yield accurate and robust contamination estimates. The proposed algorithms were used to estimate the contamination levels in an offshore well drilled with OBM. Comparisons with laboratory assays on nine fluid samples show excellent agreement, thus proving the concept of using an NMR fluid analyzer for contamination analysis in sampling applications. A secondary objective of the paper is to illustrate the benefits of integrating fluid analyzer data with open-hole and NMR logs. Such integration leads to an overall improved interpretation, particularly in terms of hydrocarbon fluid properties.
Shallow Water Flow Geopressures Arising From Confined Subsurface Slumps
Authors: Ruppelt Adrienne U. , West Charles L.
Published: December 2007

Elevated pore pressure within 1000-2500 feet of the seafloor (SWFG or Shallow Water Flow Geopressure) affects the casing program of many wells in the deepwater (>1000 feet water depth) Gulf of Mexico, the Nile delta, and other offshore drilling provinces. When SWFG sands are not properly isolated, a sustained (months in duration) brine flow may occur around the surface casing, leading to buckling of the casing and a large deposit of sand carried to the seafloor by the flow. For a SWFG blowout in the deepwater Gulf of Mexico, cased hole formation test data show the sands involved are sealed by an overlying marine transgressive Sangamon (100,000 Ma) age shale. Even though the four involved sands are separated by less than 60 feet of shale, the sands are also in pressure isolation from each other. Laboratory work on a sample of the sand carried to the seafloor shows large (> 1 p.u.) porosity loss could occur with finite strain cyles at low stress. Using these measured data, variation of seismic response of a flow sand before and during a SWFG well bore failure event has been tentative correlated to porosity losses of 1-2 p.u. A hypothesis is formed for finite strain and porosity loss along a critical stress (at shear failure) path for sand slumping during the shallow water flow event in the GB 515 #1 well. Porosity loss within the isolated or sealed SWFG sand could cause increases in pore pressure above existing levels.
Novel Drilling Fluid Eliminates Tar Problems Associated With Drilling SAGD Wells
Authors: Freeman M. A. , Stoian A. , Potapinski J. W. , Elias L. C. , Tetreault R.
Published: December 2007

Drilling Athabasca tar sand for Steam Assisted Gravity Drainage (SAGD) production is complicated by the sticky bitumen. When the buried tar has high viscosity, it is liquefied in situ and recoverd using SAGD technique. Two wells are drilled around 800 m horizontally, one near the bottom of the deposit and the other about 5 m higher. Steam is injected into the upper hole and the liquefied bitumen is collected from the lower hole.

Tar sands are generally well sorted and poorly consolidated. At typical reservoir temperatures of 10°C, the bitumen is semi-solid. The apparent viscosity of the bitumen appears to halve with each 10°C of temperature increase, and the mechanical heat generated by drilling softens the bitumen and makes it sticky.

Sticky tar adheres to the BHA, causing sand accretion and increasing torque. When the tar reaches the surface, the shaker screens quickly blind off. The sand and bitumen can also separate, building sand beds in the well and forming tar balls that block the flow line. Solvents can be used to dissolve the tar and eliminate screen blinding, but they cause unacceptable wash outs. Mud coolers have been used to remedy the remedy.

A new fluid has been used to drill SAGD wells without adhesion problems or shaker blinding, and without the use of mud coolers. It relies on a strong water-wetting agent to avoid BHA adhesion, oil-wetting surfactants to encapsulate tarry cuttings, and a rheological profile optimized for minimal well-bore erosion.

Although initially troubled with foaming, the lined-out fluid drilled near-gauge holes at rates limited by solids control equipment. Drilling time was reduced compared to similar wells, with similar fluid costs. The new fluid thus offers significant reductions in drilling costs by reducing drilling time and equipment.
Through Tubing Rotary Drilling: A Cost-Effective Method for Sidetracking Wells in Mature Assets
Authors: Kleverlaan Martijn , Lawless Angelique
Published: December 2007

Shell Exploration & Production in Aberdeen, Scotland has implemented through tubing rotary drilling (TTRD) as a cost effective method of accessing small accumulations of hydrocarbons in some of its mature assets in the UK sector of the North Sea. Working together with its contractors, the implementation of TTRD has taken place over the past 6 years. The most recent experience is a 5 well campaign on the North Cormorant platform during the past year. This paper gives an overview of the implementation process including a history of the work done, highlights and lowlights of drilling operations that have taken place to date. However, it focuses on the issues that were addressed in relation to the current campaign. Topics that will be covered are: Planning Process: An evaluation was done leading up to the current campaign to identify the areas of improvement that would yield the highest value. Resources were dedicated to the improvement initiative, beyond what would normally be assigned for conventional drilling operations.Novel Drilling Fluid Application: The conventional weighting agent (barite) was replaced by manganese tetra-oxide to give a low rheology fluid with enhanced anti-sag characteristics.Drilling Performance Optimisation: Work was done to reduce the torque requirement of the drill bits used for TTRD and match those requirements to the capability of the slim hole drilling motors for the required hole size.Equipment Upgrades: Surface equipment and downhole tools were developed and existing tools improved in order to improve performance and increase overall capability. Critical equipment that was either developed or significantly improved included: kick detection equipment, directional drilling bottom hole assembly, perforating guns, and swelling elastomer packers.

The benefit of TTRD, demonstrated by the successful campaign on the North Cormorant, is being carried forward to the rest of the Shell Exploration & Production organisation through the establishment of Global Implementation Team specifically for through tubing drilling. Shell is looking forward to realizing the benefit of this technology worldwide.
Gas Solubility in Synthetic Fluids: A Well Control Issue
Authors: Silva C. T. , Mariolani J. R. L. , Bonet E. J. , Lomba R. F. T. , Santos O. L. A. , Ribeiro P. R.
Published: December 2007

More than 90% of Brazilian oil and gas reserves lie in offshore fields and over 60% of the total reserves are located in deep and ultradeep waters. Some of the important technical problems associated with deep and ultradeep water drilling involve: i) low formation fracture gradients; ii) long choke lines; and iii) low temperatures at the mud line. The well control planning and strategy for drilling exploratory and development wells in those fields should address those technical drawbacks in order to achieve the safety requirements in a cost-effective scenario. The better understanding of gas solubility in synthetic based drilling fluids plays a fundamental role in terms of preventive (kick detection) and corrective (kick circulation out of the hole) well control practices. The present work involves PVT characterization of two organic liquids (n-paraffin and ester) currently applied in drilling fluid systems for deep and ultradeep water drilling, in Campos Basin (Rio de Janeiro, Brazil). The measurement of thermodynamical properties of the methane-liquid mixtures, such as bubble point pressure, solubility, formation volume factor of oil, formation volume factor of gas and liquid density, were performed for 158°F and 194°F temperatures. The measurements were conducted in two different apparatuses: an Hg system and an Hg-free PVT system. The results showed that the correct accounting of formation gas solubility in downhole conditions and during the kick circulation is a very important issue for safely drill deep and ultradeep water wells.
High-Performance Hermetic Optical Fiber for Downhole Applications
Authors: Wang C. , Drenzek G. , Majid I. , Wei K. , Bolte D. , Soufiane A.
Published: December 2007

Optical fibers have been used in the petroleum industry for many years; their applications range from real-time temperature and pressure measurements, data transmission, to imaging applications. In this paper, we demonstrate significantly improved reliability of recently developed hermetic, high operating temperature optical fiber. The study includes extensive testing of this fiber under controlled conditions; and a comparison with previous studies and other non-hermetic fibers.

The hermetic optical fiber of this study is coated with a thin layer of carbon, which provides excellent resistance to hydrogen permeation, water diffusion, and corrosive chemicals attack. Our results show high resistance of the fiber to hydrogen, crucial in the harsh conditions of downhole well completion.

To simulate the harsh environment, a test chamber has been built capable of exposing the fiber to temperatures up to 200°C and pure hydrogen pressures up to 120atm. Attenuation spectra from 0.8 to 1.6μ are recorded before and after exposure. At 150°C and 100atm of pure hydrogen exposure, the induced attenuation at 1.24μ is typically less than 0.4dB/km/100hours. From these spectra, we extract the permeation time constant τf as a function of temperature and thereby obtain the activation energy for hydrogen permeation through the carbon layer. The use of τf is extremely useful to describe carbon coating resistance to hydrogen ingression. Moreover, this parameter allows us to separate the characteristics of the carbon coating from the reaction characteristics of the glass with the ingressing molecules. Our experimental values of τf are significantly greater than previously published results in the literature.

In addition to its high resistance to ingressing molecules, the hermetic fiber of this study also offers enhanced mechanical fatigue resistance determined by both static and dynamic fatigue tests. This improved fatigue resistance is indicated by the high stress corrosion parameter N value ≈ 150.
Spectral Component Geologic Modeling: An Improved Method for Integrating Seismic Data into Geologic Models
Authors: Bishop Glen , Calvert Craig , Foreman Lincoln , Yao Tingting , Bhuyan Kamal
Published: December 2007

Geologic modeling and reservoir simulation provide information critical to successful commercialization of discovered and undeveloped reserves, as well as to the effective management of producing reservoirs. Often, uncertainty associated with the reservoir&s characterization and with the geologic model can be reduced by integrating interpretations from multiple data sources, most commonly from the well and the seismic data. These data types provide very different, yet complementary information to the geologic model. The well data provide information over a broad range of scales, but these data are only sparsely sampled in the reservoir. The seismic data are more densely sampled, but provide only a limited scale of information. The integration of these two data types should properly account for their scale differences. Traditional geostatistical simulation methods do not properly account for the fact that the seismic data and the well data represent very different scales of information.

Spectral Component Geologic Modeling (SCGM) properly accounts for the difference in scale between the seismic and the well data. A spectral component is an interpreted map or volume of a rock property. All spectral components contain information over a limited frequency bandwidth. A tentative geologic model is built by mathematically combining spectral components; each component providing information to the model that is limited with respect to its frequency content. The tentative geologic model is then constrained to honor the desired spatial continuity of the modeled property, the statistical distribution (histogram) of that property, and the properties measured at the well locations.

Spectral simulation is used to honor the desired spatial continuity of the modeled property. With this method, the exact and non-stationary continuity information contained within the combined spectral components can be preserved in the constrained geologic model. As a result, depositional features such as sinuous channel sands, which are observed in the spectral components, are preserved in the model. An application of SCGM is presented. Results clearly show that the SCGM model honors both the spatial distribution and the spatial continuity of the modeled property, as they are represented in the spectral components.
Abandonment Decisions and the Value of Flexibility
Authors: Begg S. H. , Bratvold R. B. , Campbell J. M.
Published: December 2007

This paper describes an investigation of abandonment decisions and shut-in policy as a function of uncertainty in oil price. We first review a fundamental error that is often made in predicting the outcome of, and hence making decisions about, systems that are subject to uncertainty: for many common models, the use of "best" estimates of the uncertain input parameters to the model does NOT result in the "best" estimate of the model's output ("best" is defined as average, or minimum error). The same argument applies to predicting output statistics, such as P10 or P90, from corresponding input statistics. This is part of the reasoning behind, for example, the use of geostatistical simulation models of the sub-surface, rather than smoothed, spatially-averaged models.

In this work the focus is on decision errors caused by temporal averaging, specifically, the "smoothing out" of oil price fluctuations over time, and by restricting uncertainty investigations to the uncertainty in parameters of smoothed price models. We illustrate these points by application to determining optimal abandonment decision policies. We show that it is better to wait for a period after first going cash-flow negative, and how to estimate the length of that time. We also show that these conclusions are relatively insensitive to the oil-price model parameters. Further we show that, if maximizing NPV is the objective, then contrary to normal operating procedures, it is more economic to choke-back production in periods of low oil price.
Use of Dynamic Modeling in Preparations for the Gullfaks C-5A Well
Authors: Rommetveit Rolv , Fjelde Kjell Kåre , Frøyen Johnny , Bjørkevoll Knut S. , Boyce Graham , Eck-Olsen Johan
Published: December 2007

Dynamic flow modeling has been an essential part of the planning for the Gullfaks C-5A well. This paper discusses the use of such modeling and presents the main results related to:

Design of operational window Transient scenarios Development of detailed procedures. Training Flow test modeling Design of under-balanced cementing

First, the operational window was defined by means of steady state modeling. Various combinations of influx rates and choke pressures were simulated to ensure that bottomhole pressure could be controlled. Also modeling was applied to ensure that proper hole cleaning was maintained during the operation. Modeling of the running of the 7" liner quantified the surge/swab pressures and laid the basis for the liner running procedure.

Next, a number of scenarios were developed by means of transient simulations. It was essential to evaluate the dynamics of the system if a fracture with high productivity was drilled through. This would assist the wellsite team detecting the situation and making the correct adjustments with the choke to maintain BHP. Also the effects of choke adjustments on the production rate as well as the transient conditions in the well were evaluated. Various procedures were simulated e.g. connection procedures in order to arrive at the optimal for this well.

Dynamic modeling was an important element in the well specific UBD training course which was held for all the personnel involved in the operation. This increased the understanding and preparedness of the crew prior to operation.

Modeling of the flow test prior to the drilling of the planned section was also performed.

The displacement of heavy kill mud out of the well under pressure was modeled prior to the operation.

Modeling of the underbalanced cementing operation was performed for the purpose of developing guidelines for controlling the choke while maintaining constant bottomhole pressure.
Pressure Stability Analysis for Aerated Mud Drilling Using an Analytical Hydraulics Model
Authors: Guo Boyun , Ghalambor Ali
Published: December 2007

Fluctuations in the borehole pressure has been generally recognized as one of the major problems in aerated mud drilling due to its detrimental impact on borehole stability and formation damage. This paper focuses on analyses of bottomhole pressure fluctuations due to circulation break and backpressure variation. The pressure fluctuations due to circulation break is characterized by the gradient loss defined as ECD less EMW. The pressure fluctuation due to backpressure change is evaluated using the pressure instability factor defined as the ratio of change in the bottomhole pressure to the change in the surface choke pressure.

Sensitivity analyses with an analytical model indicate that the gradient loss decreases with depth, increases with both liquid pumping rate and gas injection rate, and decreases with backpressure. The analyses also show that the pressure instability factor increases with depth, decreases with both liquid pumping rate and gas injection rate, and increases with backpressure. At a given depth and backpressure, it is the combination of liquid and gas flow rate, rather than the injection GLR, that determines the pressure instability factor. Following a change in the backpressure, the transition time for borehole pressure to stabilize at a new level depends on several factors including well depth, well geometry, and liquid pumping rate.

This paper presents an easy-to-use method for predicting pressure fluctuations and identifies key factors affecting the pressure stability in aerated mud drilling. The results can be applied to designing of hydraulics for Underbalanced drilling (UBD) and managed-pressure drilling (MPD) wells.
Forecasting US Natural Gas Production into year 2020: a comparative study.
Authors: Garcia Anangela , Mohaghegh Shahab D.
Published: December 2007

There are several models for predicting US natural gas production. The most referenced model is the one developed and used by the Energy Information Administration (EIA). Recently a model was developed at Texas A & M University that used neural networks in order to learn from the past when predicting the future. One of the major short comings of the existing models is the fact that they appear to be too certain about their predictions. In other words, they fail to take into account the uncertainties associated with predicting many of the parameters that are inputs into their models and treat them as a certain single values.

In this paper authors present a new model with several advantages over the existing models. First, this model treats the US Natural Gas Production as a time series with all its inherent complexities and incorporates the required methodologies during the development process. Second, this model does not use parameters such as gas price as an input. If we know the future price of gas, then predicting the production levels will not be so difficult. Third, this model does not assume that crisp and exact information is available on the future values of all the input parameters such as GDP, Population and average depth of oil and gas wells. Instead by incorporating a Monte Carlo simulation approach, it uses a probability distribution function for each of its input parameters, and hence the outcome of the model (US Natural Gas Production) is not a crisp number for each year rather it is a range that includes a minimum, a maximum and a most likely value.

The model is developed using the state-of-the-art in intelligent systems by using data up to year 1998. The model is then validated by comparing its results with actual US Natural Gas production for years 1998-2002 as blind (verification) years. During this five-year period this model outperforms all the existing models in the literature. The US Natural Gas production is then forecasted until year 2020.
Successful Application of Hydrajet Fracturing on Horizontal Wells Completed in a Thick Shale Reservoir
Authors: East Loyd E. , Grieser William , McDaniel B. W. , Johnson Bill , Jackson Randy , Fisher Kevin
Published: December 2007

The evolution of well completions in the Barnett Shale Reservoir of North Texas has moved into the realm of horizontal wells. This move was clearly evidenced by an increase from 10 permits in 2002 to more than 100 permits in 2003 to drill Barnett Shale horizontals. In late 2003 and into 2004, success with horizontal completions has possibly proliferated the most in the more economically challenging areas of the field (outside of Denton and Wise Counties) where the Viola "bottom" is poor to absent, making Ellenburger water a concern.

Conventional fracturing processes that were well defined in the vertical well stimulation arena have helped to shape the completion strategies of horizontal wellbores, such that operators generally assume that a large-volume, light-sand waterfrac stimulation will be a requirement. However, many are concerned that fracturing of uncemented liners may not provide adequate effective reservoir drainage in horizontal wells. At times, these concerns have pointed to a need for complicated and expensive multistage fracture treatments using cemented liners to get complete lateral zone coverage.

At least one Barnett Shale operator has made extensive use of microseismic fracture mapping during fracture stimulation of horizontal wells for both cemented and noncemented liner completions. Additionally, wells with cemented and noncemented casing have been completed using the relatively new hydrajet-fracturing technology and were microseismic mapped. This paper presents a comparison of varied completion techniques and what has been learned from these mapping efforts.