bluuebunny/crossref_metadata_2025 huggingface dataset:
Stimulation of the Ekofisk
Authors: Mancillas Gene , Matson R.P. , Ziara B.A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction

Discovery of the Ekofisk oil field in 1969 ended a long and frustrating search for commercial oil in the North Sea. It became the first North Sea oil field to be produced commercially and proved to be the largest oil field in proved to be the largest oil field in western Europe to date. Its success opened a bright new era for a number of European countries which formerly had to import most of their oil.

The development of the Ekofisk field in the turbulent and hostile environment of the North Sea presented many engineering challenges. Many new techniques and designs had to be developed before the Ekofisk could become a successful commercial reservoir, one of which was the stimulation design for the oil reservoir. Careful consideration had to be given to all the well information available (only one well had been drilled). Specific information about the reservoir's structure, performance, etc., was not available, due performance, etc., was not available, due to the limited number of wells drilled. Well data that was available and would influence the stimulation design included the high reservoir pressure, high bottom hole temperature, and the massive thick carbonate reservoir. The stimulation design included the development of new materials and a specific blender for performing the treatments.

HISTORY - DISCOVERY

The Ekofisk field was discovered in late 1969 by the Phillips Group in the Norwegian sector of the North Sea. The Ekofisk is located approximately 200 miles from the Norwegian coast and very near the United Kingdom-Norwegian seaward boundary line.

Oil was discovered in the Danian Formation on the Ekofisk structure at approximately 10,000 feet with the drilling of Well 2/4-1AX in November 1969.

Subsequent to Well 1AX, three additional wells, 2X, 3X, and 4X, were drilled.
The Commission On Engineering Education: Its Objectives And Program in Relation To Engineering Faculty Development
Authors: Hall Newman A.
Published: December 2007

Publication Rights Reserved

This paper was prepared for the 38th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in New Orleans, La., on October 6–9, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to published is hereby restricted to an abstract of not more than 300 words, with no Illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary. Such abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request providing proper credit is given that publication and the original presentation of the paper.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Engineering education in recent years, has fortunately been the subject of intense concern on the part of the profession and faculty. Quite naturally, these groups have the most valid reason for interest and should assume the greatest responsibility. However, this interest has not resulted consistently in a uniform expression of opinion or course of action. In fact, the diversity of approach to educational problems has presented conflicts which have intensified the difficulties facing those most intimately involved.

The Commission on Engineering Education was established to clarify educational concerns and identify goals for a direct program of action. It was organized in August, 1961 by a conference of engineers brought together under NSF auspices because it was believed engineering education could be advanced most objectively by a group which did not represent vested interests of organizations or institutions. Consequently, the Commission has dedicated itself to developing and maintaining engineering education at a maximum level of excellence by strengthening the environment and improving the effectiveness of engineering education. It is promoting those activities which will:

Increase the capabilities of individual faculty members. Provide educational resources to facilitate the introduction of advances in science and technology, to improve teaching efficiently, to encourage initiative. Develop a more adequate understanding of factors affecting the motivation and accomplishment of present and potential engineering students.
Application of Geostatistical and Fluid Flow Simulations to Evaluate Options for Well Placement
Authors: Pathak R. , Ogbe D. O. , Jensen J. L.
Published: December 2007

In this study, we apply geostatistical and flow simulations to a section of the Endicott field, Alaska to assess options for well placement. Both sequential Gaussian and sequential indicator simulations were used to model Zones 2A and 2B. Wells were then placed in the models to assess sensitivities to location and petrophysical properties. Some cases were found to have much higher productivities and lower sensitivities.

Three porosity and permeability realizations, selected from 100 realizations and representing high, medium, and low cases, were used for fluid flow simulations. Flow simulations were used to evaluate 15 potential well locations. We analyzed the performance of fully penetrating vertical and 600-ft, 1800ft, and 3000-ft horizontal wells at each location considering various well orientations, kV/kh ratios, and position in the reservoir geosystem.

The flow simulation results show that the 3000-ft horizontal well gives the best performance in most of the cases. However, the performance of the horizontal wells deteriorated rapidly with a decrease in the permeability anisotropy (kV/kh). In that case, a vertical well is a better option, especially for the thick reservoir here. The proposed method should find application in targeting infill wells in a new development.
Oil and Gas Reserve Growth-A Model for the Volga-Ural Province, Russia
Authors: Verma Mahendra K. , Ulmishek Greogory F. , Gilbershtein Andrei P.
Published: December 2007

An understanding of reserve growth in known oil and gas fields has become a critical component of energy resource analysis. Significant statistical studies of reserve growth have been published in the U.S., whereas little information is available on other regions of the world. It may be expected that in many countries the magnitude of reserve growth is different from that in the U.S. because of differences in reporting systems and in exploration and production practices. This paper describes the results of a reserve growth study in a group of largest oil and gas fields of the Volga-Ural petroleum province, Russia. The dynamics of reserve growth in these fields shows rapid reserve additions during the first 5 years of field exploration and development, which results from intensive step-out and delineation drilling. Later reserve growth is slow and is related to improvements in recovery technologies and discoveries of new pools and extensions. These two stages of reserve growth are described by two different groups of empirical models. A comparison of these models with the models developed for the lower 48 states and Gulf Coast offshore of the U.S. demonstrates that the reserve growth in the Volga-Ural province is significantly lower than in the U.S. The proposed models may be used for assessment of future reserve additions in known fields of countries that presently have or recently had a centrally-planned economic system.
Barrier-Free Learning for Well Construction
Authors: Trantham J. A. , Deagen J. M.
Published: December 2007

Well Construction and Information Technology (IT) groups are working together at ARCO Alaska, Inc. (AAI) to create a real-time, barrier free, learning environment. In this environment, engineers discover that small "jewels" of knowledge are easily shared and discovered. This is accomplished by identifying compartmentalized knowledge, breaking down organizational barriers and disseminating knowledge broadly. New technologies enable automatic data collection, publishing, and collaboration with outside contractors via the web. These new tools alone can not turn a group into a real-time learning organization. In order for this to happen, the members of the well construction groups continue to design new work processes and communication standards.
Scaling of Co-Current and Counter-Current Capillary Imbibition for Surfactant and Polymer Injection in Naturally Fractured Reservoirs
Authors: Babadagli T.
Published: December 2007

To increase capillary imbibition recovery rate and deplete matrix oil efficiently, surfactant and polymer solutions can be injected into naturally fractured reservoirs. Laboratory experiments are needed to understand the response of the reservoir rock and fluids to these applications and a scale-up process is required to quantify the recovery for reservoir conditions before injecting these expensive fluids.

This study tests the existing capillary imbibition scaling-up formulations in literature and proposes modifications to them for surfactant and polymer injection applications. Laboratory tests were performed using Berea Sandstone cores with different shapes, sizes and boundary conditions. The rock samples were surface-coated to create many different boundary conditions causing co- or counter-current imbibition or both. Kerosene, engine oil, mineral oil and crude oil were selected as the oleic phase. Brine and two different concentrations of surfactant and polymer solutions were the aqueous phase types. The capillary imbibition recovery curves were then used to test the existing scaling formulations.

It was observed that the scaling groups were applicable with certain modifications to the co-current flow of surfactant and polymer solution-oil pairs as well as the brine-oil cases. Modifications to the Mattax and Kyte's scaling group for the capillary imbibition of high IFT fluids (brine-oil and polymer solution-oil experiments) were introduced for the matrix boundary conditions, oil viscosity and wettability. In case of co-current flow, the gravity forces dominate recovery for low IFT experiments and modification to the gravity scaling group for the boundary conditions is required. For counter-current flow, however, the scaling groups were observed inapplicable even after the modifications.
Examples of Cased Reservoir Analysis in the Ventura Basin, California
Authors: Odom Richard C. , March Kathryn S.
Published: December 2007

The oil fields of the Ventura Basin are very mature with many wells drilled before the advent of modern logging tools. Despite the years of development, there remain opportunities for cost-effective production, given the great thickness of the productive intervals and the dynamic-nature of the depositional and tectonic environment that created them.

Cased-reservoir analysis in existing wells is an efficient tool to target productive intervals. The well-logs and analysis examples utilize pulsed-neutron technologies. The cased-hole neutron and density porosities from the pulsed-neutron system provide the porosity information and describe gas-bearing intervals. Water flooding and gas injection has changed many of the original fluid properties. In the log analysis examples, Carbon/Oxygen logging describes the water saturations, and Sigma logging helps in the discrimination of the sands from the mudstones.
Natural Gas: The Revolution Is Coming
Authors: Economides M.J. , Oligney R.E.
Published: December 2007

Natural gas today accounts for about 22% of the world energy demand. This figure is skewed because of the 26% gas market share in the biggest consumer of them all, the United States. In Europe, outside of the former Soviet Union, with a population of 1.5 times that of the United States, gas accounts for 19% of the market. In terms of per capita energy consumption, the average U.S. citizen consumes about 2.2 times more gas than a European. These ratios both for total usage and gas market share in the energy mix became much more lopsided for almost all countries. A move toward increasing gas use is now under way, both from a demand and supply standpoint. For example, Brazil, the world's tenth largest economy with a current gas market share of 5%, has embarked into a very ambitious plan of increasing gas use. Several gas-producing countries have also announced very ambitious plans for markedly increased gas output. These include Qatar, Oman, Venezuela and, potentially the largest of them all, Saudi Arabia. Liquefied Natural Gas (LNG) facilities are currently being built, and LNG tankers are forecast to experience very serious shortages over the next three to four years. The United States has made an emphatic move toward increased gas use. Already less than 5% of electric power generation uses oil. Well over 90% of new power generation built in the United States over the next decade will be fueled by natural gas. Gas-fired turbine manufacturing is experiencing a three-year backlog. Once manufacturing catches up with demand, the transition to natural gas will cause substantial shortages for a considerable stretch of time—covering not just the traditional peaks in winter heating but also new peaks associated with summer electricity demands. More crucial, we believe that environmental concerns, real or imagined, will push the emergence of fuel cells much faster than currently envisioned. Natural gas will be in the center of this transformation, resulting in a greatly expanded market share of gas in the world energy mix, increasing to 40–50% by the year 2020.

We present below a comprehensive analysis of the current state of natural gas supply and demand; we provide the conventional forecasts and rationalize our forecasts, which are heavily influenced by electric deregulation, LNG conversion and fuel cells.

Introduction

At the time of this writing, natural gas consumption in the United States has reached an estimated 23 trillion cubic feet (Tcf) per year. This is very near the highest consumption rate of natural gas, which was experienced in the 1972–1974 period. Figure 1 presents the history of natural gas consumption in the United States and the other G-7 countries (Canada, France, Germany, Italy, Japan and the United Kingdom).1
Experimental and Numerical Study of Drilling Fluid Removal from a Horizontal Wellbore
Authors: Biezen Ewout , van der Werff Niels , Ravi Kris
Published: December 2007

After a well has been drilled, the drilling fluid should be removed and replaced with either cement and/or completion fluids. For effective zonal isolation and optimum hydrocarbon production during the life of the well, the entire drilling fluid should be removed from the annulus. Cement and completion fluids are sensitive to drilling fluid contamination, and even a thin layer of oil-based drilling fluid could prevent the cement from bonding to the formation and the casing. In addition, for optimum hydrocarbon production, the cement sheath must be able to withstand the stresses throughout the life of the well.1

Several factors affect the success of drilling fluid removal from horizontal annuli. Under static conditions, drilling fluid usually forms a gel structure. Under positive differential pressure, the drilling fluid loses filtrate and forms a filter cake on the formation face. Sometimes the filter cake is mushy and difficult to remove, but the formation fluid can easily flow through it. The successful removal of the gel and mushy filter cake depends on the structures that form and how these structures behave under flow conditions. In addition, casing centralization affects the fluid flow profile in the annulus, which affects gel and filter-cake removal.

To investigate the mechanism of drilling fluid removal, we conducted both numerical and experimental studies. In the experimental studies, chemical flushes and spacers were tested for their effectiveness in removing drilling fluid. The experiments showed that annulus cleaning begins around the inner pipe and progresses outward at increasing fluid flow rates. Analytical fluid flow models and full 3D multiphase numerical models allowed us to estimate flow profiles and the success of removing drilling fluid under downhole conditions. The large-scale experiments and analytical/numerical modeling have led to a better understanding of the factors controlling drilling fluid removal from horizontal wellbores.
Underbalanced Drilling at its Limits Brings Life to Old Field
Authors: Labat C. P. , Benoit D. J. , Vining P. R.
Published: December 2007

Underbalanced drilling along the Gulf Coast recently brought new life to an old field. Natural gas misted with diesel was used to drill the low permeability Smackover and Norphlet formations at the Hatters Pond field north of Mobile, Alabama. The success of the project along with a four-fold increase in production has generated new interest in an old asset. This case history reviews how detailed safety hazard analysis and proper planning resulted in a safe and successful operation even under the most extreme design and regulatory requirements.
Field Application of Glass Bubbles as a Density-Reducing Agent
Authors: Arco Manuel J. , Blanco José G. , Marquez Rosa L. , Garavito Sandra M. , Tovar José G. , Farias Antonio F. , Capo Jesus A.
Published: December 2007

This communication describes preliminary results and observations of a successful application in a field environment that incorporated hollow glass spheres, also known as glass bubbles, as a density reducing agent in a drilling fluid. In this field application, a proprietary oil-in-water emulsion fluid developed by PDVSA-INTEVEP which contained hollow glass bubbles (3M) was used during the drilling of a producing interval. The oil-in-water emulsion provided a suitable fluid base, whereas the glass bubbles, by virtue of their low density, imparted a lower finished density than that of the corresponding base fluid. The density lowering capacity of the glass bubbles is proportional to the concentration of bubbles incorporated in the fluid.

The field trial substantiated that the fluid-glass bubble pair is stable, homogenous, and compatible through conventional mud motors, bits, surface cleaning equipment, and of such rheological and filtrate properties, as to lend itself to be used in low pressure reservoirs and in producing zones of high permeability.

During this field application, we were able to lower and maintain the density of the base fluid at 7.1 PPG. Additional oil production increase was observed relative to a vicinal well (vs. GF-134D) drilled with oil based fluids at an excessive overbalanced. This observation may suggest that damage to the producing zone has been avoided.

This technology is an alternative to the use of aerated fluids, with potential economic and technical advantages due to the elimination of surface compressing and air injection controller equipment, and to the simplification of operations required to avoid excessive overbalance during pipe trips.

Other potential benefits of using this low density fluid includes torque reduction as a result of higher lubricity, reduction in casing wear, higher penetration rates, decreased formation damage, lost control mitigation, and the use of mud pulse MWD tools. Glass bubbles are also a viable alternative to reduce the density of water based drilling fluids, oil and polymer-based fluids, and brines.

Laboratory tests were also carried out with conventional fluid systems to include water-based, 100% mineral oil and oil-in-water emulsions, with different concentrations of LITEDENTM in order to evaluate the potential field use of such formulations as substitutes for aerated fluids in wells which might require lower density fluids. Several formulations for the systems mentioned above were developed with the purpose of achieving maximum density reduction without affecting filtrate control or rheological properties. Fluid densities as low as 5.5 and 6.0 ppg were obtained for corresponding 100% oil and O/W emulsions based fluids.
Relative Permeability Modification in Gas-Liquid Systems Through Wettability Alteration to Intermediate Gas-Wetting
Authors: Tang Guo-Qing , Firoozabadi Abbas
Published: December 2007

The wettability of Berea and chalk samples for gas-oil and gas-water fluids were altered from strong liquid-wetting to intermediate gas-wetting. Two polymers, FC-722 and FC-759, were used to alter the wettability. FC-759 is soluble in water and some 20 times less expensive than FC-722. Gas and liquid relative permeabilities were measured before and after wettability alteration. The results demonstrated a significant increase in liquid-phase relative permeability. Gas-phase relative permeability for a fixed saturation may increase or decrease. However, because of the very high liquid mobility and reduced liquid saturation, the gas mobility also increased for a fixed pressure drop.

A number of liquid injectivity tests were also carried out. The results revealed that the liquid-phase mobility could increase significantly when the wettability of rocks was altered from strong liquid-wetting to intermediate gas-wetting. All the results show clearly that the application of wettability alteration to intermediate gas-wetting may significantly increase deliverability in gas condensate reservoirs.
Use of Solvents To Improve the Productivity of Gas Condensate Wells
Authors: Du Liangui , Walker Jacob G. , Pope Gary A. , Sharma Mukul M. , Wang Peng
Published: December 2007

Experiments have been done with a retrograde gas condensate fluid to measure the decrease in gas relative permeability due to liquid dropout below the dew point and to evaluate the use of methanol to restore the gas relative permeability. The methanol was found to increase the end-point gas relative permeability by a factor of 1.2 to 2.5 depending on the initial water saturation. A likely reason for the increased gas permeability is the miscible displacement of the condensate and water phases by the methanol. The use of an inexpensive solvent such as methanol to improve the productivity of gas wells that have been damaged by production below the dew point due to condensate and/or water blocking presents an attractive approach deserving further investigation.
Differential Scanning Calorimetry: A New Technique to Characterize Hydrate Formation in Drilling Muds
Authors: Dalmazzone Christine , Dalmazzone Didier , Herzhaft Benjamin
Published: December 2007

With the increasing number of deep offshore drilling operations, operators and service companies are confronted to more and more complex technical challenges. Extreme conditions encountered at these depths require an adaptation of the drilling muds. In particular, range of temperature and pressure (up to −1 °C and 400 Bars) are favorable conditions to the formation of gas hydrates. Hydrates are solid structures formed from water and gas: water contained in drilling muds will form under certain temperature and pressure conditions, a solid cage which entraps the gas molecules. Formation of these solid gas hydrates is liable to plug kill and choke lines as well as the annular, and may cause interruption of the drilling operation and even destruction of rig equipment. Deep offshore drilling operators are aware of this problem and some operational solutions and drilling mud formulations are proposed and utilized, but when extreme water depths are attained, classical inhibitors solutions alone may be ineffective. The usual way to determine the thermodynamic conditions of the formation of hydrates in drilling mud formulations is to use PVT cell. This technique required heavy instrumentation and often does not permit to work with a whole formulation (specially in the presence of solids). Moreover, PVT cells do not give a quantitative evaluation of the kinetic properties of hydrate formation.

In this work, we present experiments using Differential Scanning Calorimetry (DSC) to determine the thermodynamic equilibrium properties and kinetic of hydrate formation in whole mud formulation. With this technique, we measure heat transfer as a function of time, temperature and pressure and thus detect phase transition. The possibility of characterizing hydrate formation with this technique is shown for the first time on a synthetic mud formulation. Validation with PVT cell measurement and investigation of the influence of several additives (salts, solids) are performed. Hydrate formation on a whole mud formulation is underlined. This technique is easy to use and when correctly interpreted permits to determine the dangerous zones for hydrate formation.
Real Options Application: From Successes in Asset Valuation to Challenges for an Enterprise-Wide Approach
Authors: Faiz Soussan
Published: December 2007

Various "business technologies" will distinguish future industry winners. For instance, the Real Options paradigm is emerging as the state-of-the-art methodology for asset valuation. The concept of an "efficient frontier" is also making headway for Portfolio Optimization within the energy sector. The notion of Enterprise Risk Management (ERM) is being viewed as far more effective and efficient than the current "silos" in companies’ risk management practices. In addition, the proponents of Value-Based Management (VBM) are fostering a more integrated and shareholder-focused approach to performance measurement and accountability.

There is, however, a large gap in both the literature and in practice on combining Real Options with Portfolio Optimization and linking these efforts to ERM, VBM, and the broader business perspective. The ability to integrate and align these disjointed initiatives is of critical interest to senior executives. A seamless enterprise-wide approach is needed.

This paper discusses some insights and challenges of a Real Options application, a Portfolio Optimization case study, an ERM method, and a VBM concept. It concludes that while these approaches are visibly superior to their traditional predecessors, they are limited if applied in isolation. Although the paper does not provide the solution, it proposes a framework for the integration effort, which could equip executive management with a cohesive and orchestrated enterprise approach.
Use of Carbon Oxygen Logs Run in Open Hole in Wells Drilled with Oil Base Muds
Authors: Sullivan M. J. , Stewart W. F. , Belanger D. L.
Published: December 2007

The Cabinda concession offshore Angola has several oilfields where waterflood operations are being used to enhance recovery. Because the injected water has a relatively low water salinity (33 kppm NaCl equivalent seawater), detection of zones experiencing injection water breakthrough is difficult using traditional Pulsed Neutron Capture logging tools, which rely on measurement of chlorides in saline formation waters. One technique frequently employed in these circumstances is the use of Carbon Oxygen logging tools. These tools measure the relative abundance of carbon and oxygen, thereby distinguishing oil from water independent of salinity. These tools are usually run in existing wells that have been on production for some time. In some fields however, active infill drilling programs are underway where new wells are drilled through producing horizons that may have already been swept with low salinity injection water. These swept layers can be difficult to distinguish from oil-bearing intervals using conventional resistivity logs. Recently, Carbon Oxygen logging tools have been run in open hole as part of the standard open hole logging program. This has proven to be an effective means of distinguishing oil from low salinity water before casing the well, despite the influence of mud filtrate invasion.
Effect of Trapped Gas on Relative Permeability and Residual Oil Saturation in an Oil-Wet Sandstone
Authors: Kralik J. G. , Manak L. J. , Jerauld G. R. , Spence A. P.
Published: December 2007

A comprehensive set of experimental data from preserved reservoir sandstone is used to demonstrate features important to oil-wet systems not usually included in water-wet three-phase relative permeability models. The data are described by a generalized version of the relative permeability model developed by Jerauld (1997). The impact of these features on immiscible and miscible water-alternating-gas performance is estimated with type pattern simulations.

The sandstone reservoir studied shows large amounts of spontaneous imbibition of oil and traps water during secondary drainage. Oil relative permeability is almost a function of oil saturation alone while water relative permeability is significantly lower in the presence of trapped gas. Unlike most systems, the trapped gas saturation depends on the relative amounts of oil and water. While two-phase trapped gas values are consistent with values in the literature for similar sandstones, three-phase trapped gas levels are approximately a factor of two lower. The residual oil saturations for waterflooding and gasflooding followed by waterflooding are the same. Furthermore, the incremental oil production during the waterflood following gasflooding was minimal.

Two different lithologies show the same general behavior. Experiments run with different pressure drops demonstrate that the low trapped gas saturations are not due to capillary desaturation. CT scans show that little redistribution of gas occurs during trapping.
History, Trends and Evolution of Float-Over Deck Installation in Open Waters
Authors: O’Neill L. A. , Fakas E. , Ronalds B. F. , Christiansen P. E.
Published: December 2007

Float-over deck (FOD) installation is no longer a novel approach for heavy integrated decks. It is estimated that over 20 FOD installations have been carried out in open (unsheltered) waters over the past 20 years, which have proven the reliability and cost-effectiveness of this method.

FOD installation is an alternative to lift-installing integrated decks using heavy-lift crane vessels. Although the former may not be the most cost-effective solution in areas where such vessels are readily available, it is increasingly becoming an important solution for deck installations in remote parts of the world. This is due to the considerable cost associated with crane mobilisation in such areas. FOD installation also accommodates integrated deck weights in excess of the lift capacity of crane vessels.

This paper provides a database of all documented FOD installations in open waters to date and addresses the technical issues and challenges, with particular emphasis on the complexity, reliability and effectiveness of the technology used. Trends in deck weight and installation sea-states are also illustrated, confirming the growing confidence of the industry towards FOD installation. Indicative cost comparisons with alternative installation methods such as a single heavy lift or a multi-lift modular installation are also presented for some cases. The paper also elaborates on the limitations of installation methods used to date. Finally, a brief introduction is made to several recent innovations, which focus on the improvement of conventional FOD installation systems as well as the development of novel systems suitable for developments in Australia and worldwide.
An Improved Model for Predicting Separation Efficiency of a Rotary Gas Separator in ESP Systems
Authors: Harun A. F. , Prado M. G. , Shirazi S. A. , Doty D. R.
Published: December 2007

An improved model is presented capable of predicting the separation efficiency of a rotary gas separator in ESP systems. The model incorporates a new two-phase flow inducer model capable of calculating the inducer head. The inducer head generated by a rotary gas separator has been identified as a key parameter that distinguishes between a separator’s high and low efficiency regions. This information was previously determined empirically, but now can be calculated. The new model predicts more accurately the liquid rate at which a rotary gas separator should be installed. A comparison of the model’s predictions with water-air and hydrocarbon-air experimental data indicates that the improved model performs better than earlier models.
Estimation of Bottomhole Pressure in Pumping Oil Wells: Effect of High-Viscosity Fluids and Casinghead Pressure
Authors: An H. , Scott S. L. , Langlinais J. P.
Published: December 2007

The ability to monitoring bottomhole flowing pressure in pumping oil wells provides important information regarding both reservoir and artificial lift performance. Converting surface pressure measurements to bottomhole is currently accomplished by locating the fluid level in the annulus using a sonic device and then applying a correlation to estimate the density of the gas-cut liquid column above the perforations. This gascut liquid column exhibits Zero Net Liquid Flow (ZNLF) conditions where the casing head gas flows through a nearly stagnant liquid. A review of literature reveals that the correlations currently in use by the industry are based on low pressure and low viscosity data. Increasingly, operators are encountering high viscosity fluids and in some instances, casinghead gas flows into gathering systems which are not the typical low pressure systems. This paper presents recent experimental measurements for ZNLF under high viscosity and pressure conditions. The results indicate that viscosity and pressure have a significant effect on the calculated bottomhole pressures and that these effects are not accounted for in the currently applied methods. New methods are presented to calculate multiphase density, i.e. gradient correction factor, under high viscosity and high pressure conditions.
Production Data Integration Using a Gradual Deformation Approach: Application to an Oil Field Offshore Brazil
Authors: Reis L. C. , Hu L. Y. , de Marsily G. , Eschard R.
Published: December 2007

History matching of geostatistical reservoir models requires efficient tools for coherently modifying model realizations. In recent years, the gradual deformation approach has been developed and successfully applied to several simple (synthetic or pseudo-real) cases. This paper presents the application of the gradual deformation method for history matching to a real oil field located offshore Brazil.

The oil reservoir consists of turbiditic sandstones interbedded by shales and marls. The data set includes 47 wells with lithofacies description and 15 years production history. A fine scale geostatistical lithofacies model was built using the non-stationary truncated Gaussian approach. The model is conditioned to the lithofacies data at wells and takes into account the non-stationary distribution of the lithofacies. The sensitivity of the dynamic behavior with respect to the model realizations was studied. Preliminary results of using gradual deformation method for improving history matching are presented.
Multiscale Data Integration Using Markov Random Fields
Authors: Lee Sang Heon , Malallah Adel , Datta-Gupta Akhil , Higdon David
Published: December 2007

We propose a hierarchical approach to spatial modeling based on Markov Random Fields (MRF) and multi-resolution algorithms in image analysis. Unlike their geostatistical counterparts that simultaneously specify distributions across the entire field, MRFs are based on a collection of full conditional distributions that rely on local neighborhood of each element. This critical focus on local specification provides several advantages: (a) MRFs are computationally tractable and are ideally suited to simulation-based computation such as MCMC (Markov Chain Monte Carlo) methods, and (b) model extensions to account for non-stationarity, discontinuity and varying spatial properties at various scales of resolution are easily accessible in the MRF framework. Our proposed method is computationally efficient and well suited to reconstruct fine scale spatial fields from coarser, multi-scale samples (e.g., based on seismic and production data) and sparse fine scale conditioning data (e.g., well data). It is easy to implement and can account for the complex, non-linear interactions between different scales as well as precision of the data at various scales in a consistent fashion. We illustrate our method using a variety of examples that demonstrate the power and versatility of the proposed approach. Finally, a comparison with Sequential Gaussian Simulation with Block Kriging (SGSBK) indicates similar performance with less restrictive assumptions.
Fractured Reservoir Characterization Using Streamline-Based Inverse Modeling and Artificial Intelligence Tools
Authors: Barman Indranil , Ouenes Ahmed , Wang Mokiang
Published: December 2007

A new approach that combines the use of static and dynamic data in fracture modeling has been developed. The approach provides the unique opportunity to constrain the fractured models to an effective permeability derived by automatically matching well performances using a streamline-based inverse approach.

The effective permeability derived from well performances reflects the stress changes induced by fluid injection, and takes into account the increase of fracture conductivity along the present day maximum horizontal stress. Given the simplicity, robustness, and speed of the streamline based inversion, the estimation of effective permeability is proposed as an alternative to the tedious and often unreliable process of fracture modeling using stress measurements.

Because of the availability of a true integrated fracture modeling framework, where any type of data could be used when deriving fracture models, the use of effective permeability derived by inversion is able to reduce the uncertainties by providing models with better fracture prediction capability, as illustrated on a carbonate reservoir.
Effective Petrophysical Fracture Characterization Using the Flow Unit Concept-San Juan Reservoir, Orocual Field, Venezuela
Authors: Rincones J. G. , Delgado R. , Ohen H. , Enwere P. , Guerini A. , Márquez P.
Published: December 2007

The San Juan Formation is one of two producing reservoirs in the Orocual field of Venezuela. Past efforts to define a petrophysical model failed to predict fracture zones, which have been identified to be the primary source of production. The current model has used both routine and special core analysis to calibrate the logs and neural-network processing has been used to fill curves where data is lost or of unusable quality. The resulting model is based on hydraulic flow units, identified as unique and individual relationships of porosity and permeability based on lithology and derived from capillary pressure curves. The model is tuned to predict fractures in this very tight matrix sandstone reservoir and is used for geostatistical and general integrated study uses.
A Successful Completion/Perforation by Use of a Downhole Lubricator Valve: A Case Study from the Siri Field, Danish Sector, North Sea
Authors: Svendsen Ove B. , Bjørkesett Halvard , Quale Eileen A. , Gudmundseth Marianne , Malmo Bernt , Brown Irvine
Published: December 2007

To be able to lubricate long perforating assemblies (guns) in horizontal wells, and to retrieve them without killing the well has always been attractive for many reasons, both from an operational point of view and to minimise formation damage.

This paper describes a case study from the Siri Field where lubricating long gun assemblies against a tubing-retrievable downhole lubricator ball valve (DHLV) enabled running up to 1000 m of 3.5" perforation guns in two runs in a live well. This was performed without the use of a surface deployment system, and without exposing the tubing-retrievable surface controlled subsurface safety valve (TRSCSSV) to potential damage in the event of inadvertently dropping the perforation guns during completion.

Use of this equipment gives also the added benefit of considerably reducing the equipment rigup heights for Siri in the future life of the field, after the jackup drilling rig has moved off location.
Well Construction and Completion Aspects of a Level 6 Multilateral Junction
Authors: Ohmer Hervé , Follini Jean-Marc , Carossino Ricardo , Kaja Mirush
Published: December 2007

Multilateral applications have been historically constrained by the complex construction process of the junction, and the fact that the overall mechanical integrity and detailed geometry of the junction is not always known and predictable for the lifetime of the producing reservoir.

In particular, Level 61 junctions, as defined by the Technology Advancement-Multi Laterals (TAML) forum, must provide both mechanical and hydraulic integrity.

A pre-formed dual-leg Level 6 junction has been developed The design is based on an integrated geometry that increases the branch/parent diameter ratio compared to a non-formed junction using a novel metal forming technique.

The junction construction process starts when a compressed shape dual-leg junction is run in the hole at the bottom of the parent casing. Afterwards, a wireline-conveyed expansion tool post-forms the junction in a fully controlled and closely monitored process. The result of this simple construction process is a junction with an overall mechanical integrity and a known geometry.

In this paper we first describe the dual-leg junction and process related system tools, then we provide the full construction process of a multilateral well using the preformed dual-leg Level 6 junction, and finally we present the results of the successful first field installation of the system.
Optimal Control Strategy and Experimental Investigation of Gas-Liquid Compact Separators
Authors: Wang S. , Mohan R. , Shoham O. , Marrelli J. D. , Kouba G. E.
Published: December 2007

The deployment of the new technology of gas-liquid compact separators such as Gas Liquid Cylindrical Cyclone (GLCC©1) requires dedicated control systems for field applications. The control strategy implementation is crucial for process optimization and adaptation, especially when GLCCs are operated at wide range of liquid and gas flow conditions. In this study, a unique and simple control strategy, which is capable of optimizing the operating pressure and adapting to liquid and gas inflow conditions, has been developed. Detailed simulations and experimental investigations have also been conducted to evaluate the performance of the proposed control systems. The significant advantages of this strategy are: the system can be operated at optimum separator back pressure; the system can adapt to the changes of liquid and gas flow conditions; and the strategy can be easily implemented using simple PID controllers available in the market. This provides the oil and gas industry a simple, robust compact separator control technique which has the potential for offshore and subsea applications.
Oilfield Paraffin Treatments: Hot Oil and Hot Water Compared to Crystal Modifiers
Authors: Becker J. R.
Published: December 2007

Crystal Modifier chemicals have been successfully applied in several areas of the world to control deposition of paraffin waxes in production strings, pipelines, and refinery storage facilities. However, the use of these chemicals requires that they be protected from cold weather to prevent them from freezing, thus making them impossible to pump. Therefore, the practices of hot oiling and hot watering remain the main methods of paraffin wax remediation. Over the past two years advances in the technology of crystal modifier formulation have succeeded in producing modifiers that are suitable for year-round application. This new technology has made it possible to compare the effectiveness of crystal modifiers versus hot oiling and hot watering for a large sampling of production areas. Three large and geographically distant areas of production, previously on hot oiling and hot watering programs, were placed on a program of solvent cleanup and continuous and batch treatment with crystal modifier products. Case histories for these three fields are presented in this paper. Additionally some theoretical topics are also covered including the description of paraffin crystal modification and its affect on the behavior of crude oil fluids.
Low-Frequency Downhole Vibration Technology Applied to Fishing Operations
Authors: Stoesz Carl W. , DeGeare Joe P.
Published: December 2007

This paper discusses the development and the recent, successful application of downhole vibration technology as an effective, economical technique for extracting sand- and gravel-stuck tubing, pipe, and liners from wellbores. This paper shows how equipment previously considered immovable can be extracted by applying low-frequency vibration at the point where it is stuck. Furthermore, the paper describes how downhole vibration fills a technological gap between single impact jars, washovers, milling operations, and surface vibration, accomplishing these extractions at considerable cost and time savings over other approaches. Testing and field runs in which liner lengths ranging from 60 to 725 ft were successfully extracted are presented, demonstrating the efficiency of the new technology. Application identification also is addressed.
4D-Ready Towed-Streamer Data and the Foinaven Benchmark
Authors: Morice S. , Svendsen M. , Larsen L. , Kristiansen P.
Published: December 2007

Time-lapse (or 4D) seismic is emerging as a key reservoir management tool, and towed-streamer configurations offer a cost-effective method for acquiring 4D surveys. Successful 4D imaging requires that the non-repeatable noise should be weaker than the 4D signal, however, poor control of repeatability perturbations often masks any changes in the reservoir.

Analysis of the Foinaven Active Reservoir Management (FARM) 4D datasets, comparing permanently-installed sea-bed receivers with conventional towed-streamer seismic acquisition technologies, has revealed much about the factors that influence successful 4D imaging. Data from both the sea-bed-cable surveys and the towed-streamer surveys are very well repeated, with the sea-bed-cable data showing the higher repeatability. We infer that a significant factor in this success is the exacting control of acquisition parameters, and that the improved response from the sea-bed-cable surveys is due to the use of receivers that occupy identical positions in the baseline and repeat surveys.

This paper describes a new acquisition system specifically designed for reservoir characterization and 4D seismic, which enables control of repeatability factors through advances in marine seismic technology. This system will deliver the high-quality 4D seismic data that are needed to reveal subtle reservoir parameters.
So What is the Reservoir Permeability?
Authors: Haddad S. , Cribbs M. , Sagar R. , Viro E. , Castelijins K. , Tang Y.
Published: December 2007

In many reservoirs, permeability values are often available from one or as many as four sources. These permeability sources include core analysis, nuclear magnetic resonance log (NMR), wireline formation tester, and well testing (DST). However, permeability values from these sources often differ significantly. In many cases, this creates confusion as to which value of permeability should be used to best represent reservoir performance and well productivity.

In this paper, permeability values, evaluation methods, scales and applicability of all measurements are discussed and verified with field data. Factors influencing each measurement technique are also discussed.

Available permeability data from the various sources in a deep water Gulf of Mexico sandstone reservoir are considered to demonstrate how they may be used to build a model of well/reservoir performance. An accurate knowledge of permeability is critical to forecasting rates. Production facilities may be over- or under-designed if rates are inaccurately predicted, excessive capital expenditure for an over-designed facility or the inability to deliver at high rates for an under-designed facility can cost an operator and its partners dearly.