bluuebunny/crossref_metadata_2025 huggingface dataset:
An Analysis of Advection-Dispersion Ratio to Incorporate Dispersive Transport into Streamline Simulation
Authors: Jang Minchul , Lee Jaehyoung , Choe Jonggeun , Kang Joe M.
Published: December 2007

Streamline simulations have been extensively used due to its computational speed and freedom from numerical dispersion. However, many works have been applied to transport modeling without considering dispersive transport. A new term, an advection-dispersion ratio is introduced, which is defined as a relative extent of advection to dispersion along a streamline. Using the advection-dispersion ratio, analytical solution to the advection-dispersion equation is mapped onto streamlines so that dispersive transport can be effectively modeled by streamline simulation. With the advection-dispersion ratio incorporated, streamline simulation was applied to transport in an artificially fractured sample, and the simulation result was compared to experimental result. It is observed that the tracer breakthrough curve from the simulation matches well with that from the experiment. In addition, the tracer displacement profile matched that of experiment well.

By allocating various advection-dispersion ratios to streamlines, streamline simulations were performed on various fields generated by sequential Gaussian simulation to analyze the effect of the advection-dispersion ratio on transport modeling. Then, the results were compared with simulation result using a single representative advection-dispersion ratio over the flow domain. The simulation results indicate that a representative advection-dispersion ratio is applicable when the advection-dispersion ratio is large. On the other hand, advection-dispersion ratio should be allocated differently to each streamline with respect to the characteristics of the streamline, when the representative advection-dispersion ratio is small. Moreover, similar permeability is apt to be clustered spatially in a field of high correlation length, which yields diverse and contrastable streamline characteristics in the standpoint of advection-dispersion ratio. Therefore, the results using the single representative advection-dispersion ratio differ from those using various advection-dispersion ratios along individual streamlines.
The New Gulf of Mexico National Pollution Discharge Elimination System Permit: How does it Shape up?
Authors: Hall John
Published: December 2007

December 2001 marked the introduction of a new modification to the EPA National Pollution Discharge Elimination System (NPDES) Permit for Region 6 (Gulf of Mexico.) The changes related to the permit's coverage of the discharge of synthetic based fluids on cuttings. Regulators in other areas of the world, for example North Sea and Nigeria, have also permitted discharge of synthetic based fluids on cuttings. However, time has seen increasing restriction of discharge rules and has also seen operators forced to go to zero discharge of synthetics base fluids. The permitting of discharge, followed by tightening of regulations, and, sometimes, ultimate moves towards zero discharge by regulators has had a profound impact on usage, development, and availability of synthetic based drilling fluids.

This paper lists key events regarding environmental regulations and follows the developments following the introduction of the new NPDES Permit for the Gulf of Mexico from the perspective of a drilling fluid supplier and examines industry reactions to the implementation of the permit. It also seeks to answer two key questions from the supplier's perspective-"How is this rulemaking different from that seen in other areas in the world?" and "Is the next regulatory step for the Gulf of Mexico zero discharge"?
Low Field NMR Water Cut Metering
Authors: Wright Ian W. , Lastockin David , Allsopp Kevin , Evers-Dakers Maureen , Kantzas Apostolos
Published: December 2007

We have developed a new on line water cut meter using low field Nuclear Magnetic Resonance (NMR) technology. This instrument is designed for use on heavy oil systems where conventional instruments experience difficulties.

We present laboratory and field data for application of low field NMR to water cut measurements of bitumen/water mixtures. Data from successful field tests near Cold Lake, Alberta, Canada, shows that the instrument is capable of making water cut measurements over a wide range of fluid types and temperatures. We have successfully measured fluid streams with temperatures ranging from 60 to 150 degrees Centigrade and with water cut ranging from 40 to 95 percent. The instrument is capable of functioning accurately over a wide range of emulsions and/or foams and through significant variations of water salinity.

The current application is for water cut measurements on a well site. However, the instrument can be applied in any system where heavy oil, bitumen, water, gas and solid systems may be encountered. It can be used for water cut and/or for three phase (oil/water/gas) volume fraction measurements. The instrument is equally capable of performing well site monitoring for regulatory/reconciliation purposes, for characterizing produced fluids, in separation, pipelining and upgrading processes for process control and for quality testing.
New Concepts of Dual-Completion for Water Cresting Control and Improved Oil Recovery in Horizontal Wells
Authors: Inikori Solomon O. , Wojtanowicz Andrew K.
Published: December 2007

The primary advantage of horizontal wells is the long penetration and small pressure drawdown. Thus, horizontal wells have been used for developing reservoirs experiencing severe water coning problems.

However, several field experiences indicate that horizontal wells are also not free from the problem of water coning (otherwise known as water cresting). In some field reports, water breakthrough into horizontal wells could be quite dramatic and tend to erode the merit of high deliverability. Field experiences also indicate that the horizontal well fluid inflow profile is not uniform along the well but rather asymmetrically skewed toward the heel of the well. Thus water tends to breakthrough first at the heel (downstream end) and spread toward the toe-end (upstream end) of the well.

In this paper, the authors present the result of a tool developed to effectively evaluate the problem of pressure loss in the wellbore and its effect on water cresting in horizontal wells. The tool incorporates the effects of several factors such as in-situ pipe roughness, perforation size and perforation density, axial fluid influx and two-phase oil-water flow. The results could be extended to three-phase flow by adequate gas-liquid correlations.

The paper also presents a study of two innovative concepts of "smart" completions for controlling water cresting in horizontal wells: "tail pipe water sink" and "bi-lateral water sink". The technologies involve the segregated production of oil and water in a dual completion with zonal isolation. The results of this research using commercial numerical reservoir simulators indicate that dual completions are capable of reducing the incidence of by-passed oil at the toe of horizontal wells and improve oil recovery by over 7 percent.
Exploration Economics of Multizone Prospects: A Comparison With Single Zone Approximations
Authors: Mudford B.
Published: December 2007

Many deepwater exploration prospects are composed of multiple stacked zones of pay. In general, each zone has a geologic probability of success, a probability of oil, and a distribution of technically recoverable volumes. The composite distribution of technically recoverable volumes must be determined by stochastically adding together the recoverable volume distributions of each zone, while allowing for the fact that, in any given realization, one or more zones may geologically fail, and the successful zones may comprise a mixture of oil and gas zones. Frequently, the composite, technically recoverable volume distribution is then used as a starting point to determine the economic value of the prospect, under the assumption that the prospect can be treated as if it were a single zone.

In this paper we carry out a full stochastic economic analysis of a typical multi-zone, deepwater exploration prospect in the Gulf of Mexico, and contrast this with the results of a simplified analysis in which it is assumed that the composite technically recoverable volume has been found in a single zone. This simplifying assumption can lead to inaccuracies and inconsistencies in the economic analysis. In the full multi-zone case it is quite possible that the stacked zones are composed of a mixture of oil and gas zones. This can only be treated in the simplified case by assuming that costs are largely independent of the hydrocarbon type and mix. In the full analysis the mixed oil and gas case can be handled robustly. We have also found that the simplifying assumption of a single zone can lead to a significant underestimation of the number of wells required to develop a prospect. This, in turn, leads to overoptimistic economics.
Valuation of Technology and Information for Reservoir Risk Management
Authors: Raghuraman B. , Couet B. , Savundararaj P.
Published: December 2007

Reservoir risk management involves optimizing assets given inherent reservoir uncertainties and minimizing risk by reducing these uncertainties. The decision to implement any reservoir management technology is usually based on a cost-benefit analysis. Consequently, the correct valuation of valueadding technology (often based on net present value) becomes a significant part of a reservoir management process. A crucial underlying factor in such an analysis is the uncertainty in the reservoir model and its properties, and in the financial variables associated with the asset. The former includes, for example, uncertainty in properties such as reservoir geometry or permeability in the reservoir, while the latter refers to uncertainty in financial parameters such as discount rate or hydrocarbon price.

This paper discusses techniques for valuation of technology and information related to reservoir risk management. For demonstration purposes, these techniques are applied to valuation of real-time control and monitoring technologies in a reservoir with multiple uncertainties in its physical properties. Because of the presence of these uncertainties, value quantification requires a stochastic optimization of the reservoir production strategy, where the objective function includes a risk-aversion factor. By applying these techniques one can generate a decision-making table that shows the benefit of implementing a technology at various confidence levels. One can then further extend the analysis to estimate the added value to the reservoir if the uncertainties were to be reduced (or even eliminated) by implementing appropriate monitoring technologies. This process enables quantification of the value of information and is useful in designing monitoring strategies.

Such techniques are applicable in cost-benefit analysis and other decision-making activities for both a deterministic and a stochastic approach to reservoir management. They can therefore be used as tools for the valuation, pricing, and marketing of technology.
Geostatistical History Matching Under Training-Image Based Geological Model Constraints
Authors: Caers Jef
Published: December 2007

History matching forms an integral part of the reservoir modeling work-flow process. Despite the existence of many history matching tools, the integration of production data with seismic and geological continuity data remains a challenge. Geostatistical tools exists for integrating large scale seismic and fine scale well/core data. A general framework for integrating production data with diverse types of geological/structural data is largely lacking. In this paper we develop a new method for history matching that can account for production data constraint by prior geological data, such as the presence of channels, fractures or shale lenses. With multiple-point (mp) geostatistics prior information about geological patterns is carried by training images from which geological structures are borrowed then anchored to the subsurface data. A simple Markov chain iteratively modifies the mp geostatistical realizations until history match. The method is simple and general in the sense that the procedure can be applied to any type of geological environment without requiring a modification of the algorithm.
Microseismic Imaging of Hydraulic Fracture Complexity in the Barnett Shale
Authors: Maxwell S. C. , Urbancic T. I. , Steinsberger N. , Zinno R.
Published: December 2007

Microseismic monitoring has been used to image hydraulic fracture growth in the Barnett Shale. The Barnett is a naturally fractured shale reservoir, which causes significant complexity in fracture growth during well stimulation operations. Several Barnett treatments have been successfully imaged between March 2000 and December 2001. In this paper, examples will be given to illustrate the complexity and variability which is developed during the treatment as the slurry interacts with the pre-existing fracture sets. The microseismic images explain why the stimulations occasionally grow at an angle to the assumed fracture orientation and into neighboring wells. Differences in production rates from various wells could also be related to the fracture geometry. The implications of the images to reservoir management highlight the benefit of imaging individual fracture networks to avoid overlapping and for targeting potential new well locations.
A Practical Guide to Hydraulic Fracture Diagnostic Technologies
Authors: Barree R. D. , Fisher M. K. , Woodroof R. A.
Published: December 2007

Hydraulic fracturing is key to the economic success of many oil and gas fields around the world and has improved production in low permeability reservoirs for more than 50 years. Successful stimulations are engineered to place the proper type and volume of slurry based on estimating the dimensions of the optimal fracture to be created in a specific wellbore. Several commonly used technologies are available which determine important fracture parameters such as fracture dimensions, fracture orientation, fracture conductivity and proppant placement effectiveness. Fracture models are today's most widely used tool to predict the optimal frac geometry based on conditional inputs such as closure stress, pore pressure, permeability, fluid saturation and numerous other mechanical and petrophysical properties of the reservoir. In many cases, these parameters are based on assumptions rather than hard data, and incorrect assumptions then lead to sub-optimal stimulation results.

Direct near-wellbore diagnostics such as radioactive tracers and temperature logging are often used to gather information about fracture height and proppant placement effectiveness, while direct far-field diagnostics such as tiltmapping and microseismic fracture mapping are used to determine hydraulic fracture dimensions and orientation.

Direct fracture diagnostics alone only tell the story of what happened after the fact on a given well, but they can also be used to build a calibrated fracture model which accurately predicts fracture growth in a reservoir. Depending upon the critical information needed for specific fracture stimulation, one or more diagnostic tools may be applied. These diagnostic tools will be discussed and compared in order to provide a reference of widely used diagnostic tools with strengths and limitations discussed along with examples of each in use in fracture optimization.
Wettability Alteration of Diatomite Induced by Hot-Fluid Injection
Authors: Tang Guo-Qing , Kovscek Anthony R.
Published: December 2007

A series of spontaneous water imbibition experiments in outcrop diatomite cores at elevated temperatures (up to 240ºC) and pressures (up to 600 psi) were conducted by employing a high-temperature and high-pressure coreholder that is scanned non-invasively using X-ray computed tomography (CT). The results show that temperature has a profound effect on oil recovery by spontaneous water imbibition from diatomite cores; the imbibition rate and oil recovery increase with temperature systematically.

This work analyzes the effect of temperature on water imbibition behavior using a simple analytical mathematical model. This model proposed is based on the concept of imbibition potential (Pim), which is defined as the slope of the line obtained when average water saturation is plotted versus square root of imbibition time. With this model, we are able to identify the effect of viscosity ratio, interfacial tension, and wettability (all are functions of temperature) on imbibition behavior at elevated temperatures. The experimental data indicate wettability alteration towards increased water-wetness plays an important role in improving oil recovery. Experimental observations indicate that the mechanism of wettability alteration in diatomite is related to detachment of fines from pore walls. Fines detachment with increasing temperature creates fresh water-wet pore surfaces thereby increasing spontaneous imbibition recovery.
A Comprehensive Reservoir Evaluation of a Shale Reservoir—The New Albany Shale
Authors: Zuber Michael D. , Williamson Jeron R. , Hill David G. , Sawyer Walter K. , Frantz Joseph H.
Published: December 2007

This paper presents the results of a comprehensive reservoir evaluation of the New Albany shale reservoir in northern Kentucky and southern Indiana and Illinois. Although initially compared with the Antrim shale in the Michigan basin, the New Albany shale has been found to have very different production characteristics than the Antrim. This paper presents the results of a comprehensive study performed on behalf of the New Albany Shale Producibility Consortium (NASPC). The objectives of this study were to determine the controls on production characteristics of wells in the New Albany shale, understand well reserves, and ascertain the potential for future development in the play. The reservoir evaluation included all available geologic, formation evaluation, production, and reservoir data from multiple fields within the play. During this study, core testing was conducted to develop baseline properties required for reservoir evaluation.

Study results indicated that fracture characteristics within the play are the key driver for well production characteristics and reserves. In addition, we found that matrix gas porosity, bulk permeability, methane adsorption characteristics, and net pay thickness also differentiate the New Albany shale reservoir from the Antrim. The results also indicated that horizontal wells may have the potential to improve productivity and reserves within the play by specifically targeting the characteristics of the fracture pattern within the reservoir.

The results of this paper may be useful to producers in fractured shale plays who wish to improve their understanding of flow characteristics and well performance. The work presented in this paper is important because it increases the knowledge base of shale reservoir properties and characteristics and because it describes an approach that can be used to characterize shale reservoirs.
Identification of Unknown Permeability Trends from History Matching of Production Data
Authors: Grimstad Alv-Arne , Mannseth Trond , Aanonsen Sigurd Ivar , Aavatsmark Ivar , Cominelli Alberto , Mantica Stefano
Published: December 2007

We investigate into how a priori unknown large-scale permeability structures like channels/barriers can be identified from history matching of production data, using Adaptive Multiscale Estimation (AME).

With Multiscale Estimation (ME) of the permeability, we solve a sequence of parameter estimation problems with increasing resolution for the permeability until a match is obtained. With AME - and contrary to Ordinary Multiscale Estimation (OME) - the parameterization refinement is not the same all over the reservoir. We aim at introducing new degrees of freedom in the permeability parameterization only where it is warranted by the production data.

The paper describes the principles of AME, and extends AME to corner point grids on non-rectangular 2D reservoirs. On 2D synthetic examples, we demonstrate how AME is able to completely identify simply shaped large-scale permeability trends, and how it avoids over-parameterization where OME does not.

On 2D field examples, AME is found to identify large-scale trends. When the large-scale trend has a more complex shape, AME identifies a similar trend of less complex shape at approximately the same location. The identification of the permeability trends for the field examples can, however, be improved upon, and, e.g., use of coarsening (as well as refinement) in the parameterization selection will be further considered in future work.
Determination of OHIP and Aquifer Constant Without Prior Knowledge of Aquifer Models
Authors: Bhuiyan Mofazzal H. , Chamorro Alexander , Sachdeva Rajesh
Published: December 2007

This paper outlines a new technique to determine original hydrocarbon in place (OHIP) and aquifer influx constant from production and pressure history. The Hsieh et al 1.method was modified and extended in many significant respects. With the new technique, calculations can be done using either the conventional (CMBE) or general material balance equation (GMBE). The proposed method thus applies to any fluid type (gas, oil, gas condensate, volatile oil etc.). This method does not require any pre-selection of aquifer models, and it can still calculate aquifer constant, water influx quantities and OHIP values. A computer algorithm was developed to take the "subjectivity" out of the Hsieh et. al. method. The new technique was successfully verified using numerous real-life examples that involved different reservoir types. The method was incorporated and tested using the commercially available material balance program2 (OilWatTM / GasWat™)1#.
A Neural Network Model for Prediction of Liquid Holdup in Two-Phase Horizontal Flow
Authors: Shippen Mack E. , Scott Stuart L.
Published: December 2007

Accurate prediction of liquid holdup associated with multiphase flow is a critical element in the design and operation of modern production systems. This prediction is made difficult by the complexity of the distribution of the phases and the wide range of fluid properties encountered in production operations. Consequently, the performance of existing correlations is often inadequate in terms of desired accuracy and range of application. This investigation focuses on the development of a neural network model, a relatively new approach that has been successfully applied to a variety of complex engineering problems. Data from five independent studies were used to develop a neural network for predicting liquid holdup in two-phase horizontal flow. A detailed comparison with existing empirical correlations and mechanistic models reveals that the neural network model shows an improvement in overall accuracy and performs more consistently across the range of liquid holdup and flow patterns.
A Rational Approach to Multilateral Project Planning
Authors: DeMong Karl , Mason Stan , Al-Yami Hussein
Published: December 2007

In the past, junction construction technology has driven the design of multilateral wells. This practice has led to technical successes that may or may not have met all of the operator's desired well objectives. These projects have often been regarded as less than successful from an economic point of view. This regard is partly due to the way that junction construction has been viewed. Junctions are presently classified by looking at the technical differences in how they are constructed, such as TAML levels (Technology Advancement – Multi Laterals)1. Although this method is suitable for looking at junction construction complexity, it does not address directly what the junction does in service. Another approach would be to drive the design using information about reservoir/production requirements. Looking at functional groups of junction features will allow the drilling or completions engineer to make sense of the myriad of available junction systems. This technique can help optimize the multilateral junction type selection for a given project.

The process of planning multilateral projects from conception through well design will be discussed with a focus on using a functional classification map to clarify the junction requirements. The Functional Classification Method will assist engineers in comparing equipment options. This comparison is accomplished by, first, defining the reservoir and economic drivers, and, then, by selecting the appropriate junction attributes. Furthermore, the method will provide a process for assembling the data required to prepare the final well design and to prepare precise tender documents. To illustrate this method, recent examples from the Middle East will be presented.
Application of Water Injection/Falloff Tests for Reservoir Appraisal: New Analytical Solution Method for Two-Phase Variable Rate Problems
Authors: Levitan Michael M.
Published: December 2007

The challenges of reducing or eliminating emissions associated with well testing operations during reservoir appraisal have revived interest in water injection/falloff tests. However, the two-phase flow and injection induced temperature changes associated with injection/falloff tests complicate the problem of well test analysis. Strictly speaking, these effects make the pressure transient problem non-linear and preclude using conventional superposition technique to construct solutions for variable rate problems.

In this paper, we present a new analytical method for accurate solution of the pressure transient problem for two-phase flow associated with water injection/falloff tests. The solution algorithm allows one to compute the solution for any step-wise constant rate sequence that includes multiple injection and falloff periods. The method is general and can be used for water injection governed by any physically meaningful relative permeabilities as well as for pistonlike displacement.
Quantifying Production Impairment Due To Near-Wellbore Condensate Dropout and Non-Darcy Flow Effects in Carbonate and Sandstone Reservoirs With and Without Hydraulic Fractures in the Ghawar Field, Saudi Arabia
Authors: Ahmed Mahbub , Al-Qahtani M. Y. , Zillur Rahim
Published: December 2007

Hydraulic fracturing in the sandstone and carbonate reservoirs has been adopted as the primary means to enhance production from the gas wells in the Ghawar field of Saudi Arabia. The initial incremental production from acid treatments is readily noticed from all stimulated wells in the Khuff carbonates. For the Pre-Khuff sandstones, because of the sanding tendency of the unconsolidated formation, selective perforations and indirect fracture treatments are performed to stimulate the wells. Thus the incremental production is not ascertained through actual production data, rather the post-fracture production is compared to the simulated pre-fracture potential. In either case, as the production continues and the reservoirs are depleted, production impairment occurs due to potential water encroachment, condensate build up around the wellbore, and changes in non-Darcy flow effects as gas enters production string.

This paper presents a comprehensive study of the impact of pressure depletion on production for Ghawar gas- condensate reservoirs. The paper quantifies the effect of condensate dropout on the well productivity with and without induced hydraulic fractures. The effects of non-Darcy flow have also been investigated and presented. A compositional model has been used to forecast and optimize long-term production under various reservoir conditions and operational scenarios.
A Fast and Direct Method of Permeability Measurements on Drill Cuttings
Authors: Egermann P. , Lenormand R. , Longeron D. , Zarcone C.
Published: December 2007

Permeability is one of the most important petrophysical parameter for reservoir characterization but the most difficult to obtain. Logs provide a good estimate of porosity and saturations, but the accuracy on permeability derived from NMR is rather poor. So far, reliable values of permeabilities are only obtained from laboratory measurements on core samples for local measurements and well testing for a larger scale averaged determination.

We present an original method for measuring the permeability of drill cuttings without any specific laboratory conditioning (cleaning, coating, etc.). A volume of about 100 cc of cuttings is placed in a pressure vessel. The cell is then filled with a viscous oil. The process of oil invasion into the cuttings always traps a certain amount of gas. When a pulse of pressure is applied on the cell, the oil enter into the cuttings thanks to the gas compressibility. The permeability is then derived from the dynamic of the oil invasion by using a simple model.

The method was tested by using various samples of crushed rock samples of known permeability. An excellent reproducibility and a good agreement between cores and cuttings permeabilities were found for many decades of permeabilities. This method presents many advantages. The measurements can be performed in a few minutes, leading to the possibility of operating on-site during drilling. The limitations of the method are mainly related to the size and the representativity of the drill cuttings.

In developing this method, our purpose is not to replace core analysis, but rather to provide an additional cheap and quick information on reservoir characterization.
Modeling of Wax Deposition in Pipelines from Irreversible Thermodynamics
Authors: Banki Reza , Firoozabadi Abbas
Published: December 2007

Wax deposition in flowline of some crude oils and gas condensates in offshore is a serious problem. Deposition often reduces flow capacity and may block the line and reduce flow rate and increase the production cost substantially. In the last ten years, there have been a number of studies in modeling the deposition processes. All these models assume that the Fick's law of diffusion adequately describes the mass diffusion flux of wax-forming species from the oil or gas phase towards the wall. Wax deposition in flowlines is the result of radial temperature gradient and subsequent diffusion mass flux of species in the radial direction. However, the diffusion mass flux of species in the radial direction cannot be described by the Fick's law of diffusion. In this work, we first write the expression for diffusion flux in terms of: 1) molecular diffusion, and 2) thermal diffusion. Thermodynamics of irreversible processes is used to model the diffusion flux at non-isothermal conditions. We avoid the use of chain rule to relate composition gradient to temperature gradient. We also include the radial convective velocity in problem formulation for the laminar flow for the first time. In our formulation, both the mass balance and energy balance are written for a multicomponent two-phase solid-liquid mixture. A control volume method is used to solve the coupled problem of mass, momentum, and energy balances. A numerical example for a binary mixture shows that at long times, of the order of several days and longer, both molecular and thermal diffusion affect the hardening of the layer in which the wax forms.
Subsea Heat Bank - An Alternative Thermal Insulation Method
Authors: Falk Kristin , Kaste Vegard , Håheim Svein , Damsleth Per
Published: December 2007

Subsea equipment for oil and gas production such as manifolds, X-mas trees and templates require thermal insulation in order to prevent too rapid cool-down during a production shutdown, potentially causing hydrate formation that can plug the piping. The insulation materials used today are expensive to produce and time consuming and costly to apply, yet may still leave hard-to-access areas with inadequate protection.

A Heat Bank where the subsea equipment is covered and the fluid trapped inside is heated during normal production is proposed as an alternative to conventional insulation. During shutdowns the heated fluid inside the insulated cover keeps the production equipment warm.

This article gives a detailed description of the Heat Bank and the analysis methods used for design. A thermal model based on empirical relations for natural convection and the Boussinesq approximation illustrates the functionality of a Heat Bank. This analytical model is also compared to CFD (Computational Fluid Dynamics) simulations.

The analysis reveals that the Heat Bank concept offers significant increase in cool-down time compared to traditional solutions. Other advantages include potential cost savings, reduced engineering and manufacturing times, and avoiding cold spot problems that are difficult to resolve with conventional methods. This opens for new possibilities for cost-effective field development in deep water where thermal insulation is critical to flow assurance and thereby field development economics.
Assessment and Modeling of High Permeability Areas in Carbonate Reservoirs
Authors: Massonnat G. , Pernarcic E.
Published: December 2007

In carbonate reservoirs, heterogeneity is usually driven both by the depositional and the diagenetic patterns. When original reservoir properties have been strongly modified by dissolution, the assessment and the modeling of karstic high permeability areas constitute key issues during reservoir appraisal.

In this paper, a very innovative methodology is proposed for the evaluation and modeling of reservoirs in which dissolution occurred at an early stage, and was controlled by sequence stratigraphy.

Using stochastic models of depositional facies built using Neptune (a modeling methodology/tool that uses cubes of facies proportions derived from paleobathymetry), the probability for facies to be affected by early karstification is evaluated. This can be possible thanks to the 3D grid of paleobathymetry previously computed with Neptune.

Then, the distinction is made between the regions potentially exposed to dissolution, and the regions with no chance to be exposed. The last stage consists in simulating petrophysics according to the depositional facies and its diagenetic behavior.

Such a methodology enables to take into account the 4D aspect of the reservoir construction. The prediction and the management of the areas of emersion are possible, and contribute to obtain significant advances in the realistic aspect of the 3D distribution of reservoir properties in stochastic models. Moreover, consistency between sedimentology, diagenesis, and petrophysics is input at a very high level in the model. This makes possible to preserve the key heterogeneity in reservoir models for fluids flow simulation.

Application to an oil field in Middle East illustrates the methodology.
3D Modeling of Stratigraphically Controlled Petrophysical Variability in the South Wasson Clear Fork Reservoir
Authors: Jennings James W. , Lucia F. Jerry , Ruppel Stephen C.
Published: December 2007

Petrophysical heterogeneity in the South Wasson Clear Fork (SWCF) reservoir and other shallow-water platform carbonates in the Permian Basin and elsewhere is composed of a large-scale stratigraphically controlled component and a small-scale poorly correlated component. The large-scale variability exists as a flow-unit-scale petrophysical layering that is laterally persistent at interwell scales and produces highly stratified reservoir behavior. Modeling these large-scale heterogeneities as trends using moving averages within a high-resolution sequence-stratigraphic framework reduced the requirement for arbitrary kv/kh adjustments to inhibit cross-flow in waterflood simulations. Carefully controlled power-averaging effectively captured the rate-enhancing effect of the small-scale variability.
Characterisation of Low Permeability Gas Condensate Behaviour by Intensive Reservoir Monitoring
Authors: Richardson G. J. , Roux J. F. , Quinn P. , Harker S. D. , Sides L. E.
Published: December 2007

The Alwyn North complex is located in Block 3/9a of the northern North Sea, UK sector. Production commenced in 1987 from the Brent and Statfjord reservoirs. In 1995, the presence of an economic hydrocarbon accumulation in the Triassic was proven by platform well 3/9a-N33.

The Triassic geological environment encountered is semi arid, with moderate to high sinuosity channels, lacustrine and floodplain deposits. The Triassic Upper Lunde reservoir section is thick (approximately 700m) but the net to gross and permeability are low. Individual sand body dimensions can vary from tens of metres up to the order of several kilometres. The fluid is a gas condensate in the upper 450m of the reservoir overlying a volatile oil.

Intensive reservoir monitoring has proved invaluable in improving the understanding of field performance. Downhole permanent pressure and temperature gauges have been installed in all wells since the second appraisal well. Sixteen PLTs had also been run in the accumulation by the end of 2001, which allied to MDT and downhole gauge data, allowed to calculate the connected volume to the first six wells by two different methods.

The downhole gauges have also been used to monitor the evolution of the productivity index of the wells. Moreover, time lapse Pressure Build Up analysis has been carried out to investigate the evolution of the effective permeability thickness and skin factor with time. A quantification of the impact of condensate drop out has been attained, and a first correlation against petrophysical properties developed.
Recipe for Success in Ultradeep Water
Authors: Ehlig-Economides C. A. , Economides M. J.
Published: December 2007

Generally, for sandstone reservoirs, shallow deposits tend to be unconsolidated containing heavy oil, and deep deposits tend to be hard rock of low permeability containing gas. The result is an overall leveling of mobility, which relates directly to well potential. Carbonate reservoirs offer significant departures from sandstone trends, and this explains why 8 of the 10 largest and most prolific reservoirs are carbonate formations.

Typical trends are altered when a significant portion of the depth to the formation is water depth. More or less, the formation age to depth correlation follows depth below mud line rather than below the water surface. However, the fluids may have experienced pressures and temperatures that would accelerate the maturation process from heavy oil to light oil and, even, gas. The result would be much lower than typical fluid viscosity in very large- permeability sediments, leading to high mobility and extraordinary well productivity.

The paper makes the case that under ultra deep waters, in sedimentary environments such as the Gulf of Mexico, offshore Brazil and West Africa, reservoir quality and productivity can be readily inferred and even more to the point, the depth at which specific grade of hydrocarbons can be found. In particular, very large natural gas reservoirs are likely to lie beneath oil reservoirs, the latter containing also large volumes of gas in solution.

Information from some of the largest ultra-deep-water accumulations of hydrocarbons shows correlation of depth versus mobility, which is contrasted with data from terrestrial reservoirs. This phenomenon is explained through basic principles.
Improved Quantification of Fit-for-Purpose Saturation Exponents with a Maturing Core Database
Authors: Worthington Paul F.
Published: December 2007

A fit-for-purpose saturation exponent is specific to a given rock type and to a particular interpretative algorithm for the evaluation of water saturation. This concept is expanded to include the degree of maturity of the core database. Four data scenarios are enacted to derive data-specific values of fit-for-purpose saturation exponent using two type-algorithms. The first scenario assumes no core data beyond measurements of water saturation and resistivity index using simulated formation water. The second draws additionally on a measurement of porosity for each desaturated core plug. The third scenario further requires a dual-salinity determination of intrinsic formation resistivity factor. The fourth and most comprehensive scenario calls for a more complete electrical characterization of a core plug through multiple-salinity conductivity measurements. The value of these scenarios is examined by comparing the resulting predictions of water saturation with those obtained through the reference Scenario 4 and by cross-comparing the predictive performance of the type-algorithms.

The outcome is practically the same for the two type-algorithms. The first data scenario is erratic. The results of the type-methods converge through Scenario 2, for which similar water saturations are predicted by the two algorithms. Scenarios 2 and 3 furnish predicted values of water saturation that agree well with those resulting from Scenario 4. Because Scenario 2 has the smallest data requirement of these three approaches, it is proposed as the most effective way of deriving a fit-for-purpose saturation exponent and thence obtaining a meaningful evaluation of water saturation. This scenario therefore allows data needs to be optimized with the further containment of uncertainty in integrated reservoir description. Thus, both costs and risks can be reduced simultaneously.
Multiphase Flow: Can we take advantage of hydrodynamic conditions to avoid hydrate plugging during deepwater restart operations?
Authors: Leporcher Emile , Kinnari Keijo , Labes-Carrier Catherine , Maurel Philippe , Vandersippe Wilfried
Published: December 2007

High water flowrates envisaged in deepwater oil production systems create severe technical hurdles. In steady-state flow design conditions, adequate insulation of moderate length subsea flowlines and risers is expected to maintain the fluids out of the hydrate domain. The restart operation after shutdown will on the other hand need specific operational guidelines and design solutions to avoid hydrate plugging. Operational procedures may involve hot crude displacement or injection of thermodynamical inhibitors. Plug formation has by far a more serious consequence on the production regularity at the deepwater environment than at shallow water. A new R&D project was launched to identify cost effective and easily implementable procedures and build more confidence on transient operations with particular focus on start-up. Restart operations were experimentally simulated on a properly instrumented multiphase pilot loop in order to observe and analyse the flow conditions within and outside the thermodynamic hydrate domain. Different fluid systems were tested at different hydrodynamic conditions. The results suggest that a high energy hydrodynamic start-up procedure would allow to restart the production within the hydrate domain while low energy start-up would promote formation of hydrate plugs. In the low energy start-up the presence of the oil phase was observed to reduce the risk for hydrate plug formation.
ESPs and Intelligent Completions
Authors: Konopczynski M. R. , Moore W. R. , Hailstone J. J.
Published: December 2007

The value of intelligent well completions combined with ESPs comes from the capability to restrict or exclude production from specific zones experiencing water or gas breakthrough. This technology may be applied to horizontal wells, multilateral wells, wells that produce from commingled reservoirs, or wells that exploit layered, compartmentalized, or heterogeneous reservoirs. The control of production and water and/or gas breakthrough permits more efficient operation of the downhole pump, and improves ultimate hydrocarbon recovery. This paper presents the benefits of synergy, technologies available, and the issues that must be considered when combining intelligent wells with ESPs. A theoretical example is presented that illustrates the economic benefits of combining the two technologies, and it is followed by an offshore case history that puts theory to practice.
What is the Magic of Water in Producing Sand?
Authors: Vaziri Hans , Barree Bob , Xiao Yuxing , Palmer Ian , Kutas Mike
Published: December 2007

We performed a comprehensive sand prediction study of several deep, HPHT wells within a large reservoir and the findings revealed that, for these wells, common criteria based on critical drawdown, minimum bottomhole pressure, depletion or fluid velocity failed to predict the outcome by a relatively large margin. All these wells were subjected to relatively high levels of drawdown and also very high fluid velocities and, with the exception of one well, none showed any sanding until water production was encountered.

In this paper, we provide a rationale for why water can be highly effective in inducing sand production and we support our argument using advanced numerical modeling. This exercise also ranks the performance of some of the common tools and theories that are conventionally used for sand prediction. We also provide reasons why some of these models do not perform satisfactorily for the cases studied.

The originality of the work is in demonstrating that prior to sand production, the dis-aggregated rock (i.e., individual sand particles) around the wellbore is basically held together by the capillary tension which is destroyed by water flow. While the capillary tension appears to be insignificant (as it is in the order of 1 psi or so), it provides a significant resistance against sand mobilization. The importance of this issue has been quantified using advanced numerical modeling. This concept is vastly different from the previous theories that propose water weakens the rock through chemical interaction or changing the relative permeability.
Pressure Transient and Decline Curve Behaviors in Naturally Fractured Vuggy Carbonate Reservoirs
Authors: Camacho-Velázquez R. , Vásquez-Cruz M. , Castrejón-Aivar R. , Arana-Ortiz V.
Published: December 2007

This study presents a new way to model high secondary porosity, mainly vuggy porosity, in naturally fractured reservoirs.

New solutions are presented for two cases, where there is no primary flow through the vugs, which is an extension of the Warren and Root model, and where dissolution process of pore throats has created an interconnected system of vugs and caves. In both cases there is an interaction between matrix, vugs, and fracture systems. New insights are provided.

Both pressure and production responses during transient and boundary dominated flow periods are explored. In transient well tests, for the case where there is no primary flow through the vugs, a change of slope could be present during the transition period. Thus, this study shows that slope ratios of 2:1 of early or late-time segment versus transition segment do not necessarily imply transient interaction between matrix and fractures. It is also shown that the presence of vugs and caves may have a definitive influence on decline curve and cumulative production behaviors; therefore it is necessary to incorporate vuggy porosity in the process of type curve match.

Finally, the use of the methodology obtained in this work is illustrated with synthetic and field examples.