bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Neural Networks for Predictive Control in Drilling Dynamics
Authors: Dashevskiy D. , Dubinsky V. , Macpherson J. D.
Published: December 2007

Real-time monitoring of BHA and drill bit dynamic behavior is a critical factor in improving drilling efficiency. It allows the driller to avoid detrimental drillstring vibrations and maintain optimum drilling conditions through periodic adjustments to various surface control parameters (such as hook load, RPM, flow rate and mud properties). However, selection of the correct control parameters is not a trivial task. A few iterations in parameter modification may be required before the desired effect is achieved and, even then, the result may not be optimal. For this reason, the development of efficient methods to predict the dynamic behavior of the BHA, and methods to select the appropriate control parameters, is important for drilling optimization.

The approach presented in this paper uses the power of Neural Networks (NN) to model the dynamic behavior of the non-linear, multi- input/output drilling system. Such a model, along with an optimizing controller, provides the driller with a quantified recommendation on the appropriate corrective action(s) required to bring the system to an optimal drilling condition.

Development of the NN model used drilling dynamics data from a field test. This field test involved various drilling scenarios in different lithologic units. The training and fine-tuning of the basic model utilized both surface and downhole dynamics data recorded in real-time while drilling. Measurement of the dynamic state of the BHA was achieved using data from downhole vibration sensors. This information, which represents the effects of modifying the surface control parameters, was recorded in the memory of the downhole tool. Representative portions of this test data set, along with the corresponding set of input-output control parameters, were used in developing and training the model.

Test results are promising: There is good agreement between the dynamic behavior of the BHA predicted by the NN model and the actual measured BHA response. In addition, the test established criteria for selecting the most important input-output parameters and for selecting representative data sets for building and training the model.

This analysis has demonstrated a promising approach to simulation and prediction of the dynamic behavior of the complex multi-parameter drilling system. This method could become a powerful alternative to traditional analytic or direct numerical modeling and its utilization could be extended beyond drilling dynamics to the field of drilling control and optimization.
Horizon Modeling Using a Three-Dimensional Fault Restoration Technique
Authors: Hoffman Karen S. , Neave John W.
Published: December 2007

Rigorous, internally consistent three-dimensional subsurface models are extremely useful in interpretation, mapping, well planning, and simulation pre-processing. The geospatial technique to create these models has been in use for several years, and complicated, highly faulted structures (including overthrusts and other multi-valued surfaces) have been modeled quite successfully. Often, however, the gridding process used to create the horizon surfaces required additional control points, and the shape of the overall structure was not necessarily continued from one fault block to another. A new algorithm has now been developed that uses a three-dimensional model of the faulting process itself to restore data to a pre-faulted condition. Displacement on a given fault surface can vary laterally as well as in depth, and faults which terminate within the model volume are of course accommodated. All horizons are used simultaneously in the process of creating the fault displacement model, which eliminates problems with sparse control or narrow fault blocks. The structural surfaces are then calculated in unfaulted space, and the faulting model is used to transform the resulting surfaces back to the proper structural position. Not only is this algorithm significantly faster, but it also mimics the post-depositional faulting process and produces a geologically consistent model. This consistency and integrity mean that greater confidence can be placed in the model, improving volume calculations and allowing placement of wells with greater precision. The reduced cycle time allows a greater range of scenarios to be modeled and evaluated, thus enabling better risk assessment in complexly faulted fields.
How Could You Possibly Predict the Value of 3-D Seismic Before You Shoot It?
Authors: Head Kim J.
Published: December 2007

It is relatively easy to estimate the cost of acquiring, processing and interpreting 3-D seismic data, but what about predicting its value? Some prediction is needed in order to make a business case for acquiring the additional data.

The Value of Information (VOI) can be estimated by combining a number of financial and statistical analytical methods. The VOI will ultimately depend on two key components: the possible impact on the amounts and timing of expenditures and revenues, and on the resulting Net Present Value (NPV) of the anticipated cash flow stream; andthe possible impact on the Probability of Scientific Success (Ps).

Published historical information from several companies shows that 3-D data has reduced structural uncertainty, increased reserves by identifying by-passed pay zones, improved drilling success rates, reduced the number of development wells required through optimum well positioning, led to faster development programs and faster pay-out, and terminated numerous prospects. The impact of these effects can be estimated based on industry experience.

This leads to evaluating how the additional data might impact the drilling and capital expenditure program. This could range anywhere from condemning the prospect to drilling a significantly larger number of wells and building proportionately larger gathering and processing facilities, which in turn could delay revenues and expenditures. When the realm of possibility is understood, the potential effect on the Net Present Value of the anticipated cash flow stream can be estimated.

Understanding the potential impact on the cash flow stream makes it possible to determine the Expected Value of Perfect Information (EVPI). Since no information is perfect, the EVPI will represent an upper limit on the VOI. Residual uncertainty will determine the actual value of the additional information.

This leaves the possible effect on the Probability of Scientific Success. There are a number of methods for estimating this effect including Delphi methods, Monte Carlo simulation, and using published industry data. Regardless of which method is used, internal consistency will be critical to producing a reliable estimate.

Once the possible effects on NPV and on the Probability of Scientific Success are known, the Value of Information can be predicted using a Decision Tree method. It then remains to compare the value of information with the cost to determine whether to proceed.
Use of Time-Lapse Resistivity Log Responses in a Horizontal Well to Understand the Evolution of Polarization Horns and Anisotropy
Authors: Gomes R. M. R. , Allen D. F. , Hurley N. F. , Peeters M.
Published: December 2007

The purpose of this study is to analyze the evolution of polarization horns and resistivity anisotropy as invasion progresses in a horizontal well drilled through a turbidite sandstone reservoir. Polarization horns are spikes of resistivity tool response that occur in highly deviated and horizontal wells. Resistivity anisotropy occurs when the resistivity measured in one direction in a formation is different from that measured in another direction.

The study area is the Albacora field, Campos basin, offshore Brazil. The reservoir is Upper Albian in age and is characterized by a sequence of massive and laminated sandstones with thin (20-30 cm) zones completed cemented by calcite. The horizontal well was drilled with salt-saturated mud and logged using a logging while drilling (LWD) 2 MHz resistivity tool. Seven time-lapse logs were obtained between 60 and 1120 hours after drilling. The time-lapse measurements show significant changes in both polarization horns and resistivity anisotropy as invasion progressed.

Two anisotropic sandstones with different types of layering were identified from offsetting vertical wells and correlated to the horizontal well. The first contains low-porosity calcite-cemented layers in which resistivity "horns", absent in the initial LWD log, developed over time. The second contains low permeability fine-grained layers which result in resistivity anisotropy on the initial LWD log.

Methodology included reservoir characterization using cores, well logs, mini-permeameter and petrophysical data from offset vertical wells. The Coates free fluid and Archie equations were used to calculate resistivities from mini-permeameter, porosity and rock type data. A geologic and invasion model was created and tested by the iterative use of tool-response modeling.

Results show that the peaks in the 2 MHz resistivity logs are polarization horns, which developed during the invasion process because of growing resistivity contrast between calcite-cemented layers and adjacent invaded sandstones. In the non-cemented parts of the reservoir, where low permeability streaks are controlled by textural variation and pore geometry, anisotropy effects occurred but no polarization horns developed.
The State of the Global E&P Industry: Is the World Running Out of Oil?
Authors: Iledare Omowumi O. , Pulsipher Allan
Published: December 2007

Abstract1

This paper examines trends in recoverable oil reserves and performance measures in the global upstream petroleum industry for evidence to support or reject the view that the world is running out of oil. The performance measures discussed include the appreciation ratio of recoverable reserves; the replacement rate of produced reserves; reserves to production ratios; and the equitable depletion index. The empirical analysis of these indicators suggests a growing world abundance of crude oil and no strong evidence to support the imminent worldwide petroleum exhaustion theory. The analysis shows that the global oil supply market is well positioned to support even a modest growth in world petroleum demand despite institutional and regulatory barriers on resource development in some of the more intensely explored and developed regions of the world. In fact, the current estimate of worldwide remaining recoverable reserves can sustain the current worldwide production rate for at least the next two to three decades, ceteris paribus, assuming a tolerable reserve-life index of twenty years.
Competitive Strategies and Strategic Positioning of Oil Companies in the International Oil Business: Theory and Practice in Perspective
Authors: dos Santos Edmilson M
Published: December 2007

The purpose of this article is to analyze the concepts of competitive strategy and strategic positioning of firms in the international oil industry. The author adopted the model of competitive strategy and strategic positioning of enterprises established by Michael Porter, from the University of Harvard. Despite being one of the most well known authors on strategic management and competition theory, Michael Porter has not very often been studied and considered by those analyzing the global oil competition game. This study tries to fill this gap, by presenting a general theoretical overview of Porter's model and then by applying it in the study of the evolution of the upstream oil business.
Simulation of Process to Control Severe Slugging: Application to the Dunbar Pipeline
Authors: Henriot V. , Courbot A. , Heintzé E. , Moyeux L.
Published: December 2007

The severe or terrain slugging is a periodic phenomenon due to liquid accumulation at the low points of a pipe, leading to a temporary blockage. Periodically the upstream pressure increases and generates liquid slugs, for which the instantaneous flow-rate increases to several times the nominal flow-rate. To prevent such phenomena in multiphase production pipelines, a proper design and a control strategy of process equipments are required to avoid operational problems.

The TACITE compositional code is able to simulate the behaviour of transient multiphase flow in pipeline with process equipments such as controllers, valves, separators and lateral injectors which could be used to prevent severe slugging phenomena during production.

The 22 km long, 16" diameter Dunbar pipeline is designed to transport the Dunbar multiphase production to the Alwyn platform. Due to its profile, this pipe is typically subject to riser induced severe slugging for some given operating conditions corresponding to low flow-rates.

The TACITE code has been used to simulate the Dunbar pipeline in the low flow-rate region where riser-induced severe slugging occurs. For the same rates, different slug control schemes have been tested and the simulation results demonstrated that some of them can control or even eliminate the severe slugging phenomenon. This illustrates that these slug control schemes can be easily investigated and tested by use of a transient simulator. Also the simulation results demonstrate that the use of a transient simulator is essential in the engineering design phase of a slug control scheme.
Fracturing Bypassed Pay in Tubingless Completions
Authors: Olejniczak S. J. , Swaren J. A. , Gulrajani S. N. , Olmstead C. C.
Published: December 2007

Intervals with marginal production potential are often bypassed during the early stages of reservoir development. As existing reservoirs mature, production from these bypassed intervals offer a more economical alternative for production enhancement over either in-fill or re-drilling operations. Effective fracture stimulation of such payzones using conventional techniques can be limited by a variety of operational and economical considerations.

The integration of coiled tubing operations with hydraulic fracturing procedures overcomes many of the constraints associated with the stimulation of bypassed payzones. Specialized bottomhole assemblies are used to isolate existing perforations. A high pressure coiled tubing workstring transports the fluid and proppant system. The coiled tubing also protects the existing well tubulars from the high pressures experienced during fracture stimulation. A viscoelastic fracturing fluid is preferred over conventional polymeric fluids. This fluid exhibits significantly reduced frictional pressures and hence achieves the desired injection rates under such pressure-constrained conditions.

This paper describes the operational and design aspects of the coiled tubing fracturing procedure. A field case study is finally presented to demonstrate the economical benefits realized by this methodology.
An Empirical Model for Three-Phase Relative Permeability
Authors: Blunt Martin J.
Published: December 2007

We present an empirical model for three-phase relative permeability that overcomes the limitations of current formulations, such as Stone's methods.1,2 We provide a self-consistent treatment of wettability, changes in hydrocarbon composition, different saturation paths, and the trapping of oil, water and gas. The theoretical development is motivated by a review of recent three-phase experiments. The model is based on saturation-weighted interpolation between the two-phase values.3 To account for the effects of wettability we apply saturation-weighting to all three phases. By writing the relative permeabilities as unique functions of a flowing saturation, the model predicts the behavior for any sequence of saturation changes and accounts for trapping. Layer drainage, which allows oil relative permeabilities to be extrapolated to low saturation, is included for water-wet media. The model ensures smooth changes in relative permeability with changes in hydrocarbon composition and tends to the appropriate limits as the gas and oil become miscible. The model is tested against the data of Oak and co-workers.4,5 We show that it is necessary to include layer drainage and oil trapping to predict three-phase oil relative permeability at low oil saturation accurately.
A New Method of Measuring Relative Permeabilities for Calculating Gas-Condensate Well Deliverability
Authors: Mott Robert , Cable Andrew , Spearing Mike
Published: December 2007

Well deliverability in most gas condensate reservoirs is reduced by condensate banking when the pressure falls below the dew point, but the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region.

Fevang and Whitson1 have shown that the key parameter in determining well deliverability is the relationship between krg and the ratio krg/kro. They also suggested an experimental technique for measuring krg as a function of krg/kro using core plugs.

We have applied the experimental pseudo-steady-state technique proposed by Fevang and Whitson to long cores at high pressure and temperature, measuring relative permeabilites under conditions which are similar to the near-well region of a gas condensate reservoir. A gas condensate fluid is introduced into a core whose pressure is below the dew point of the fluid. The condensate saturation in the core builds up until it becomes mobile and a steady state is reached, reproducing the mechanism which occurs in the reservoir. By varying the fluid composition, core pressure and flow rate, it is possible to measure all of the relative permeability data needed to predict well deliverability, including the increase in mobility at high capillary number.

We describe the experimental techniques and present results for a sandstone core from a North Sea gas condensate reservoir, using a 5-component synthetic fluid. The results show a clear increase in mobility with capillary number, at flow rates which are typical of the near-well region.

The pseudo-steady-state technique measures relative permeabilities and does not require saturations to be measured. The dependence of krg on krg/kro can be used directly in pseudopressure methods to calculate well deliverability. We also describe how the data for krg versus krg/kro can be used to define parameters for empirical correlations of relative permeability versus saturation, so that the results can be used in reservoir simulators.
Organisational Design and Systems for Effective Safety and Environment Management
Authors: Chakraborty Ashok B.
Published: December 2007

This paper addresses vital issues pertaining to effective functioning of the safety and environment management (SEM) set-up in an organization. The findings of the paper are based on a project study undertaken, covering functioning of the discipline, "its organisational design, development, performance and supporting administration" in selected organizations both upstream and downstream in petroleum sector. The study entailed analysis of systems in vogue i.e. organisational set-up, objectives, functions, performance parameters, monitoring systems etc. and suggests an optimal systematic approach necessary to ensure implementation and monitoring of SEM in the organisation.

The findings of the study highlights non-existence of either uniform or standardised systems in the industry as a whole emphasis everywhere, being more on compliance with statutory requirements than in the evolving and development of SEM as a holistic and integral core of all functional activities in the organisation.

Effectiveness of safety and environment management in an organisation requires, defining of policies, objectives, activities, key performance areas, as well as development of core competencies among others.

An effective SEM facilitates implementation of total loss control, environment protection, compliance with statutory requirements, codes and standards, company's safety and environment policies and achievement of international levels of recognized safety and environment management. The requirement of safety case demonstrates, that the risk to persons in installation's be properly controlled and each safety case should be subject to formal acceptance by the regulator before operations commence and calls for an effective SEM to be in place, in professionally managed organisations.

Implementation of SEM policies and programs lead to reduction of accidental losses, improves overall productivity maintain environment protection and boosts organizational image.
Expandable Tubular Solutions
Authors: Filippov Andrei , Mack Robert , Cook Lance , York Patrick , Ring Lev , McCoy Terry
Published: December 2007

Two challenges facing operators as the energy industry moves into the next century are accessing of new reservoirs that currently cannot be reached economically and maintaining profitable production from older fields. Recent advances in one of the oldest and most fundamental areas of exploration and production, namely tubular technology, will play a key role in meeting these challenges.

A method has been developed whereby the diameter of solid tubulars can be expanded downhole. This paper will describe the process and how this significant technological breakthrough provides cost-effective solutions to several tubular problems that have loomed as obstacles to comprehensive reservoir exploitation. In deepwater and subsalt environments such as the Gulf of Mexico, the ability to expand casing and tubing in-situ enables hole-size maintenance and conservation of internal tubular diameter for increased efficiency. Hence, operators are less likely to run out of hole diameter before evaluating all pay zones. Operators can now use smaller holes to drill deeper vertical wells or to extend the reach of deviated wells to access untapped reservoirs. In older fields, existing wellbores can be retrofitted with expanded tubulars for repair purposes or to increase strength and integrity. In the latter case, deeper high-pressure objectives can be supported, and thus, new in-fill wells can possibly be reduced in number or even eliminated.

In addition to a description of the process employed to expand solid tubulars, the paper will present applications of expandable tubular technology and results of large-scale testing that has been conducted in support of the applications. Potential commercial applications are also presented.
Multiphase Pressure Pulses for Quick-Acting Valves: Offshore Testing
Authors: Falk Kristin , Gudmundsson Jon Steinar
Published: December 2007

Offshore tests were performed by quickly closing a valve by the wellhead. The rapid pressure signals, created by this valve closure, were registered at three different locations upstream of the valve. The effective actuation time of the valve was about. 0.5 second. The tests concluded that the velocity of sound in the multiphase mixture could be predicted using a homogeneous assumption. The pressure waves were attenuated because of friction, but also chokes and bends were important attenuation mechanisms for the rapid pressure waves in multiphase flow.
Case Studies of Expanding Cement To Prevent Microannular Formation
Authors: Baumgarte C. , Thiercelin M. , Klaus D.
Published: December 2007

To improve our understanding of cement debonding linked to microannulus formation and, in particular, to develop better non-shrinking cements to ensure zonal isolation, a well simulating annulus experiment has been developed and tests with expanding cements have been performed. The expansion experiments demonstrate that expanding cements can prevent the formation of a microannulus if the cement properties are designed with respect to the rock properties. A good application for expanding cements is the isolation of gas storage reservoirs. Two examples are shown to demonstrate the efficiency of expanding cements.
Stochastic Reservoir Modeling Constrained to Dynamic Data: Local Calibration and Inference of the Structural Parameters
Authors: Ravalec Mickaële Le , Hu Lin Y. , Noetinger Benoît
Published: December 2007

This paper presents a new geostatistical approach, called general inversion method, to incorporate dynamic data (pressure transient, well production, water cut…) into a reservoir model. It essentially involves two basic tools: the Fast Fourier Transform-Moving Average (FFT-MA) generator and the gradual deformation method. The FFT-MA generator produces unconditional Gaussian-related fields that can be perturbed on the basis of the gradual deformation principles. Thus, the initial structure of the realizations is preserved. Integrating these two primary algorithms within an optimization process yields the general inversion procedure. This method is outstanding for at least three points. (1) Unlike the traditional inverse approaches, the general inversion method easily accounts for the constraint relative to the prior geostatistical information; (2) the permeability/porosity distribution can be perturbed globally or locally; (3) the general inversion method makes it possible to condition the permeability/porosity distribution and the structural (or geostatistical) parameters (mean, variance, correlation length…) at once. Because of these distinct facilities, it makes sense to qualify the suggested inversion scheme as a general one.

The suggested approach was applied to a few synthetic examples. These ones were designed to address key issues such as the characterization of the permeability distribution, the updating of a reservoir model to integrate newly obtained data, and the estimation of the correlation length from well data.
Geological and Production Problems Solved by Recognizing the Strike Slip Component on Reverse Faults, Block I, Lake Maracaibo
Authors: Chatellier J- Y. , Sifontes R. de , Mijares O. , Muñoz P.
Published: December 2007

Despite years of oil production and numerous geological and geophysical studies, no structural and sedimentological model succeeded to adequately describe the reservoir architecture or match the production behaviour in Block VLA-31. Around a newly acquired 3-D seismic a multidisciplinary team has integrated all of the available information and came up with a radically different geological model that is coherent with the production history. The newly interpreted faults are reverse but no repetition of section is ever observed. We identified and visualized these faults through various means and discovered the strike slip component responsible for the previous mis-interpretation of the faut system.
Multiphase Flow Conditioning Using Drag-Reducing Agents
Authors: Kang C. , Jepson W. P.
Published: December 2007

Experimental study has been performed in a 10-cm diameter, 36-m long, multiphase inclinable Plexiglass flow loop. Superficial liquid velocities between 0.5 and 3 m/s andsuperficial gas velocities between 2 and 10 m/s in 2 degree inclined pipes were examined. A 2.5 cP oil at 25 °C was used and water cut was 50%. The experiments were undertaken at a pressure of 0.13 MPa and a temperature of 25 °C with carbon dioxide as the gas. Influence of DRA on the flow characteristics such as pressure gradient, slug translational velocity, the height of the liquid film, slug frequency and Froude number using Drag Reducing Agents (DRA) has been studied. The DRA concentrations of 10 ppm and 50 ppm were used in this study.

The DRA was effective in reducing the pressure gradient at all liquid and gas velocities. At a superficial liquid velocity of 1 m/s and gas velocities of 2 and 6 m/s, the pressure gradient decreased from 544 Pa/m to 377 Pa/m and from 793 Pa/m to 477 Pa/m in 2 degree upward inclination at a concentration of 50-ppm DRA. The corresponding DRA effectiveness was 31% and 40% respectively.

Slug translational velocity did not change much with addition of DRA. But the slug frequency and the height of the liquid film decreased with addition of DRA, which led to a decrease in pressure gradient. At a superficial liquid velocity of 0.5 m/s and gas velocities of 2 and 8 m/s, slug frequency was reduced from 21 to 16 slugs/minute and from 18 to 14 slugs/minute in 2-degree upward flow at a DRA concentration of 50 ppm. Froude number increased with addition of DRA. At a superficial liquid velocity of 0.5 m/s and superficial gas velocity of 2 m/s, the Froude number increases from 4.7 to 6.3 when 50 ppm DRA was added.
A Methodology for Asphaltene Control in Production Facilities in North of Monagas, Venezuela
Authors: Ali J. , Betancourt J. , Avila C.
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
Improving Asset Performance Through Application of A Structured Decision Process
Authors: McGee M. D. , DeFoe P. R. , Robertson D. I. , McConnell J. D.
Published: December 2007

Company experience, external benchmarking and the application of best practices all contribute to improved capital efficiency and reduced cycle time. Combining these practices with a value-driven decision structure yields a powerful methodology for advancing a business opportunity from inception through completion. Many upstream petroleum companies currently use, or are developing, this type of methodology to improve reservoir characterization and development practices.

Through direct experience in a variety of operational situations within the Gulf of Mexico, a five-step generic decision model evolved that is straightforward, intuitive and scaleable. Core to the process is the initial definition of the opportunity, assessment of value, decision-makers, deliverables and the assignment of accountability to advance the opportunity to the next decision point. The result is a customized roadmap from opportunity identification to the post-implementation evaluation of results.

Any business process change within an active production operation is likely to meet organizational resistance. Unlike previous initiatives, this process has been well received, primarily by establishing a useable plan that is developed by the individuals directly responsible for advancing the business opportunity. Returning immediate value to the participants in the form of alignment of business value with technical detail and uncertainty has also aided acceptance and use. The authors have been directly involved in a variety of applications including complicated infrastructure retrofit projects, pipeline riser repairs, owner operated and non-operated development projects, well planning and operation support activities. The majority of applications are tangible, real-world situations that all operators routinely face.

Each application contributed to the evolution of the model. Lessons learned by the authors and their peers will be presented including cases that illustrate and reinforce essential principles of the process. Conclusions, in the form of quantified financial and technical results, will also be presented.
A New Approach for Economic Evaluation of Horizontal and Vertical Wells in A Sensitive Formation
Authors: Permadi A. K. , Permadi P. , Pamungkas J.
Published: December 2007

Severe formation damage in horizontal wells has been frequently reported. Many theoretical works related to this subject have also appeared in the literature. This indicates that such damage is a serious problem that can considerably affect the economics of horizontal well applications. The purpose of this paper is to present a new approach for evaluating the economic advantage of a horizontal well as compared to the vertical well case in a sensitive formation.

The new approach employs concepts of production loss analysis and the maximum cost ratio (MCR), respectively, to evaluate short and long term production and economic performances. MCR here is defined as the ratio of horizontal-to-vertical well drilling and completion costs arriving at the ratio of net present values of 1.0.

Results demonstrate that, although production performance of a vertical well is generally more sensitive to formation damage, the production loss can be much higher in the horizontal well causing a considerable economic loss when converted to dollars. Based on the analysis of MCR, it is found that (1) the costs limit of a horizontal well is controlled by the degree of damage severity, permeability, and oil price and (2) MCR is well correlated with the standard economic criteria as well as the production performance. In general, the costs limit decreases with damage severity and oil price and as reservoir permeability increases. Overall, the approach proposed can be used as a valuable tool for the economic analysis and provides engineers guidance for optimizing the drilling and completion design when a horizontal well project must go on.
Near-Wellbore Halo Effect Resulting from Tip Screenout Fracturing: Its Direct Measurement and Implication for Sand Control
Authors: Upchurch E. R.
Published: December 2007

This paper presents the findings of an investigation to determine whether or not a near-wellbore "halo" is generated during the process of fracture stimulating a well in a soft, unconsolidated formation. The investigation delves into whether net-pressure generation has any effect on the halo’s formation and, finally, whether the halo could be utilized by petroleum operators as an inexpensive way to control formation sand production.

The results from 4 fracture stimulations in perfectly vertical wells are the primary data used in this investigation. In each case, all necessary steps were taken to ensure that the collected data would show conclusively whether or not the halo occurred and, more qualitatively, to what extent a significant net-pressure increase (resulting from a tip screenout) affected the halo’s formation. All data presented here resulted from direct downhole measurements, either by bottom-hole pressure gauges or by specialized azimuthal GR logging tools that can directionally measure gamma ray intensity.

To date, the possible existence and benefit of the halo has been a topic of conjecture. This study represents the first attempt at directly confirming the existence and extent of the halo under actual downhole conditions.
The Nominal Sand Control Screen: A Critical Evaluation of Screen Performance
Authors: Underdown D. R. , Dickerson R. C. , Vaughan William
Published: December 2007

Over the past few years, several "premium" sand control screens have been introduced into the market. The proliferation of new screens has raised questions about how to choose the proper sand control screen for a particular formation. In order to address this concern, a project was initiated at Chevron to devise a method to evaluate sand control screens.

As a result of this program, a method has been standardized for the evaluation of sand control screens. The method known as the Screen Efficiency Test shows the relationship between the normalized sand control characteristics (i.e., Sand Control Factor) of the screens and the normalized length of time it takes a screen to plug under a certain set of conditions (i.e., the Performance Factor). The results of Screen Efficiency tests to evaluate several sand control screens for a North Sea and West Africa field are discussed in the paper.

The data in this paper also documents that the numerical rating given the screens by the manufacturers are generally not very useful in understanding the sand control rating of the particular screen, or comparing screens from different manufacturers. In addition, the effect of particle size distribution and sand concentration on the relative performance of sand control screens was demonstrated.
Transient Pressure Solution in the Presence of Pressure Drop in the Wellbore
Authors: Ding Y.
Published: December 2007

Horizontal and multi-lateral wells are increasingly used in reservoir engineering to improve the oil recovery. To optimise the efficiency of these wells, it is necessary to develop semi-analytical methods which are simple, fast and accurate, to study the transient pressure behavior. Moreover, the pressure drop in the wellbore, which has sometimes a strong impact on the pressure transient behavior, has to be incorporated in the modelling.

In this paper, the boundary integral equation, based on single layer heat potential, is used at the wellbore boundary to describe the transient phenomena. The pressure drop along the well length is considered. The Galerkin type approach is used to solve the boundary integral equation. Using linear Galerkin approach allows to give good approximation for the extremity effect, especially in the presence of the pressure drop in the wellbore. The pressure drop along the well length can be quickly and accurately evaluated using the linear Galerkin approach then using the commonly used line source method. The implicit Newton's technique is discussed to solve the nonlinear flow equation in the wellbore. The proposed method can be used to study the pressure solution for any number of multilateral wells, as well as selectively perforated wells.
A New Formulation for Simulating Near-Miscible Displacement Processes
Authors: Zhou Dengen , Jensen Clair , Tang Ray , Arif Hozef
Published: December 2007

Gas injection processes are most efficient at miscible/near-miscible conditions. Simulating such processes accurately is a challenge in terms of computer power and numerical stability. Recent advances5–10 in gas injection research suggest that a few key tie-lines, as determined from the phase behavior of the system, control miscibility development. The properties of gas and oil at the displacement front can be directly determined from the phase behavior of the system. Consequently, we propose a new Todd-Longstaff (T-L) formulation for simulating miscible/near-miscible displacement processes based on this recently-developed concept. The new formulation requires specification, at the displacement front, of the hydrocarbon phase densities and viscosities, and the gas saturation as a function of pressure. These properties are obtained from the key tie-line composition and pressure information. This use of key tie-line properties enables accurate definition of the fluid properties and miscibility of the system without using any empirical parameters.

Comparison of the new formulation with a fully implicit compositional model shows excellent agreement, for continuous gas-injection process 2D models used for the Rangely Field. Excellent agreement was obtained between the new formulation and the compositional formulation for continuous gas injection processes. The new formulation not only matches the oil production rates, gas/oil ratios and reservoir pressures, but also matches the saturation distributions that are often more difficult to obtain. The new formulation can be easily implemented by modifying an existing T-L formulation.
NGH on FPSO - Slurry Process and Cost Estimate
Authors: Gudmundsson J. S. , Andersson V. , Durgut I. , Levik O. I. , Mork M.
Published: December 2007

A hydrate slurry process is being developed for capturing associated gas on FPSO's. Natural gas hydrate contains 180 Sm of gas per m3 solid hydrate. It is this property that makes hydrates attractive for storage and transport of natural gas. Hydrate mixed with crude oil and refrigerated to -10 C remains stable at atmospheric pressure, for practical purposes. A capital cost estimate for a FPSO-based hydrate slurry process was carried out for 1,440,000 Sm3 associated gas and 16,000 Sm3 crude oil. The marginal capital cost was 160 million US dollars (the hydrate process only). The cost estimate was expanded to a hydrate slurry chain consisting of FPSO-based production, shuttle tanker transport and land-based receiving teminal. The hydrate chain consts were compared to transporting natural gas by a subsea pipeline. It was argued that hydrate slurry technology should be used for distances greater than 220 km.
Effect of Flow Through a Choke Valve on Emulsion Stability
Authors: van der Zande M. J. , van Heuven K. R. , Muntinga J. H. , van den Broek W.M.G. T.
Published: December 2007

When oil is produced under high water-cut conditions, oil in water emulsions can be formed. The break-up of oil droplets predominantly takes place in the choke valve. We have conducted laboratory experiments to investigate the effect of flow through a choke valve on the oil-droplet-size distribution in the emulsion. In these experiments the choke is modeled as a circular orifice in a pipe. The droplet sizes after break-up can be correlated to the mean energy dissipation rate per unit mass in the orifice. The experiments have been conducted with two set-ups on a different scale. The relation, which we have derived for the maximum stable droplet diameter downstream of the orifice can be applied to both scales. Furthermore the effect of oil viscosity on the droplet sizes after break-up has been investigated.
Quantification of Various Factors Affecting Emulsion Stability: Watercut, Temperature, Shear, Asphaltene Content, Demulsifier Dosage and Mixing Different Crudes
Authors: Kokal Sunil , Al-Juraid Jamal
Published: December 2007

This paper discusses problems related to emulsions that have been encountered in a large Saudi Arabian field. This is a unique field lying both onshore and offshore and is producing from seven different reservoirs. These oils range in viscosities from 2 cP to over 10 cP (@ 22°C) and API gravities range from 28 to 40. The n-pentane asphaltene content varies from 0.2% to over 7% and watercut for producing wells ranges from dry wells (0% watercut) to over 70%. These properties provide an interesting case of operational problems in oil-water separation. The problems include increased incidents of shorting in the separator, tripping of equipment and increased demulsifier consumption.

This paper presents the results of a comprehensive study that was initiated to understand the main causes of emulsion formation in the field. The factors investigated were watercut, temperature, shear, asphaltene content, demulsifier dosage and mixing different crudes. These factors were quantified with a new water-oil separation index that was developed to measure emulsion stability. The results show a strong correlation of asphaltene content in the crude oil with the water-oil separation index or emulsion tightness. Photomicrographs of high asphaltenic crude oil also shows the presence of organic particulate and a generally lower water drop size. These emulsions were videotaped at high magnification using a novel flow-through cell and the visual information has helped our understanding of how emulsions are stabilized by the organic films or "skin" on the water droplets. Recommendations are made for reducing and optimizing demulsifier dosage by adding chemical additives. Many lessons learned are applicable to any crude oil treating facilities.
Inflow Fluid Typing in Screened Horizontal Completions Using a Pulsed Neutron Holdup Imager
Authors: Maher Tom , Trcka Darryl
Published: December 2007

In order to determine if the current well placement was effectively draining the reservoir, a logging program was initiated in a horizontal well completed with a pre-packed screen using conventional production logging, pulsed neutron capture, and pulsed neutron holdup logging instruments. The objective was the monitoring of depletion and the identification of produced fluids along the wellbore. The logging results showed adequate reservoir drainage and suggest that the presence of the pre-packed screen may, under certain conditions, assist in the identification of produced fluids by pulsed neutron holdup imaging.
Production Logging Problem Description in October Field, Gulf of Suez
Authors: Ibrahim Adel A. , Mostafa Azzam
Published: December 2007

Production Logging Tools have significantly helped reservoir management in October field. Direction of water movement within the Nubia reservoir was understood by production logging indicating an active water rise as the primary driving mechanism. Over 100 PLT logs (PLT's) completed on 74 wells in October field have been selected for this study. A computer program is developed to analyze these PLT's systematically with the possibility to correlate the results to corresponding measured data when available. These PLT's were utilized to control water production by identifying proper placements of Through-Tubing Bridge Plugs (TTBP) for water shut-off (WSO).

In special cases, when water cut increases, old PLT data can be used to estimate the progress of zone water out without running an additional PLT. This article describes a technique to re-allocate the production within wells based on previous PLT data from the same well. Based on the success of this back-calculation method, over $25,000 per WSO in October field has been saved by eliminating an additional PLT.

Experience in October field indicates that results of production logging analysis using conventional tool configuration are not sufficient to make decisions for WSO work over. Well head measurements, reservoir driving mechanism, and direction of fluid movement should also be utilized.

Direct PLT interpretation has led to non-representative results for over 78% of the studied wells. The standard PLT analysis usually shows a misleading water production within the different sets of perforations along the well. This problem was first recognized by WSO results through which water was proven to enter the well from the bottom interval only. These errors were first attributed to hole deviation, however, field scale investigation indicated that other factors are involved since the problem was encountered in vertical wells as well. Gradio-manometer's poor accuracy is believed to be the main reason for such non-representative results.
Breaking of a Paradigm: Geology Can Provide 3D Complex Probability Fields for Stochastic Facies Modelling
Authors: Massonnat Gerard J.
Published: December 2007

Stationarity of the random function is the key property of stochastic models to the extent that wrong hypotheses could lead to very unrealistic reservoir modeling for flow simulations.

When non stationarity is suspected at the scale of the domain to be modeled, geologists usually propose either geological drift or seismic attributes to constrain stochastic models.

However, in both cases, confidence in the soft data is limited by the rough aspect of the trends from geological input, the scale problem, and the quality of correlations between the random function and the variables from seismic data.

This paper presents an original approach for building complex 3D prior probability fields of geological facies. It constitutes a very challenging way of integrating two major advances in geosciences in recent years: geostatistics and sequence stratigraphy.

From facies descriptions on cores and logs, palaeobathymetry curves of deposits are constructed for each well. Logs of the accommodation potential (increment of space available for sediment accumulation) are then produced from those curves and deposit thicknesses in the wells.

A Principal Components Analysis of data in all wells makes it possible to separate the signal into two components: a common factor which represents the tectono-eustatic activity at field scale (easily extrapolated), and residuals which correspond to local variations in subsidence. 3D grids of accommodation potential and palaeobathymetry can then be modeled, with respect to the time intervals within each layer.

Geological inversion is therefore possible and leads to the proposal of a complex 3D prior probability field for facies modeling, with different organizations in both the transgressive and the prograding parts of the sequence.

When constrained by such trends, stochastic modeling (object based or SIS) can render very realistic images of reservoir heterogeneity.

This method was applied successfully in carbonate and mixed (silici-clastic and carbonate) platform reservoirs, in which properties are highly variable and non stationary.