bluuebunny/crossref_metadata_2025 huggingface dataset:
Emerging Petroleum-Oriented Nanotechnologies for Reservoir Engineering
Authors: Evdokimov Igor N. , Eliseev Nikolaj Yu. , Losev Aleksandr P. , Novikov Mikhail A.
Published: December 2007

The paper describes experimental/analytical research aimed at modification of petroleum technologies to "nanotechnologies" by accounting for molecular processes in nanocolloids of native petroleum fluids.

Our results show that in course of traditional technological operations, macroscopic properties of petroleum media (viscosity, density, pour point, etc.) may exhibit abrupt changes caused by currently uncontrolled microscopic phase transitions in nanocolloids. In particular, our experiments provided phase diagrams of petroleum nanocolloids, which show critical parameters, highly unfavorable for industrial processing of petroleum. E.g., petroleum fluids may practically solidify at RT after a short-time residence at the temperature-defined phase boundary of ca. 28–35°C; native crudes of diverse origin exhibit sharp viscosity/density peaking at several composition-defined phase boundaries which are relevant to compatibility problems. Contrary to widespread assumptions, the current properties of petroleum nanocolloids (and, hence, the current properties of petroleum fluids) are not defined solely by current technological parameters. Of equal/decisive importance are the details of a preceding history of reservoir development.

We conclude that proper recovery "nanotechnologies" should be designed and performed with an understanding of importance of the complex nanophase diagrams of petroleum fluids. Such technology should include specifically designed processes (employ specifically selected parameters) to purposely avoid/instigate particular phase transformations in petroleum nanocolloids in order to improve (or, at least, not to ruin) the practically important bulk properties of petroleum. With respect to immediate practical applications, it should be emphasized that the discussed phase diagrams contain only "the most obvious" nanophase boundaries, reflect our current knowledge of structural transformations in petroleum and should be subjected to further investigation.
Transient Fluid and Heat Flow Modeling in Coupled Wellbore/Reservoir Systems
Authors: Izgec B. , Kabir C. S. , Zhu D. , Hasan A. R.
Published: December 2007

This paper presents a transient wellbore simulator coupled with a semianalytic temperature model for computing wellbore-fluid-temperature profile in flowing and shut-in wells. Either an analytic or a numeric reservoir model can be combined with the transient wellbore model for rapid computations of pressure, temperature, and velocity. We verified the model with transient data from multiple gas and oil wells, where both surface and downhole data were available. The accuracy of the heat-transfer calculations improved with a variable-earth-temperature model and a newly developed numerical-differentiation scheme. This approach improved the calculated wellbore fluid-temperature profile, which, in turn, increased the accuracy of pressure calculations, at both bottomhole and wellhead.

The proposed model accurately mimics afterflow during surface shut-in by computing velocity profile at each timestep and its consequent impact on temperature and density profiles in the wellbore. Surrounding formation temperature is updated every timestep to account for changes in heat-transfer rate between the hotter wellbore fluid and the cooler formation. Optional hybrid numerical differentiation routine removes the limitations imposed by the constant relaxation-parameter assumption used in previous analytic-temperature models.
Cementing Technology for Low Fracture Gradient and Controlling Loss Circulation
Authors: Ravi Kris , Savery Mark , Reddy B. R. , Whitfill Don
Published: December 2007

The main objectives in well construction are to maximize reservoir deliverability, reduce remedial jobs, and minimize nonproductive time (NPT) during drilling and cementing. One of the key factors to help maximize reservoir deliverability is the ability to reach the target reservoir depth with a minimum number of casing points and maximum production tubing size for the completion. Losses during drilling and cementing should be controlled to reduce unplanned casing points and minimize the NPT.

These challenges are severe in depleted and low-fracture-gradient formations. Engineered solutions to control loss circulation and to place cement slurry in these environments are presented and discussed. Controlling loss of circulation during well construction is more than just selecting the proper type of lost circulation material (LCM). The engineered solution discussed in this paper correlates the formation and LCM properties for effective control of losses. In situations where LCM alone may not reduce the losses, the use of chemical sealants such as polymers and special cement systems are discussed. The special cement systems can be designed to meet the specific needs such as acid solubility for easy removal, thixotropy, and filtrate loss.

Cement slurry for primary cementing across low-fracture-gradient and depleted formations should be designed to meet the density requirement so that it can be placed in the annulus and losses can be minimized. Ultra-low-density cement slurries, as low as 5.4 lbm/gal, are presented and discussed. Case histories are also presented to illustrate field implementation procedures, and the optimization of cement slurry designs to meet well requirements is discussed as well.

The results presented in this paper can be applied in well construction to control loss circulation and cementing across depleted and low-fracture-gradient formations, which ultimately should help reduce NPT and maximize well production.
Site Safety Management of a Growing Drilling Activity: Is Continuous Improvement Achievable?
Authors: Saintpere Stephane , Touboul Nicolas , Hidayat Ramadhan
Published: December 2007

In 2002, TOTAL E&P management requested all the different divisions to implement actions plans to improve the HSE performance of the company.

The purpose of the paper is to present and discuss the HSE Performance of the drilling activity during this 3 years period through the examples of 2 different affiliates in Indonesia and Gabon.

TOTAL Indonesia has gone through an impressive increase of its activity (100 wells drilled per year) over the last 3 years, with the arrival of 5 drilling units (total of 9 drilling units on relatively long term contracts).

On the other hand, TOTAL Gabon is a mature affiliate, trying to extend the production plateau by performing re-entries on existing production installations during short term drilling campaigns.

The first part of the paper will present the particularities of the drilling activity on the different fields, the HSE context and organization, and the objectives set by the management.

The second part will establish an interesting comparison between the road accidents statistics in France and the accidents on the Indonesian drilling units. It will highlight the existence of the well known plateau which is reached and how it is reached. A selection of site examples (both from the previously mentioned Asian and African affiliates) will illustrate the various statements, and the distinction between hardware improvements (technical modifications, new equipment...) and soft improvements (procedures, safety meetings, hazards observation programs...) will be established.

The conclusion will discuss the fundamental question of the continuous improvement of the HSE Performance, in particular how to go beyond the plateau. Based on the analysis of this 3 years long intensive drilling period, it will present the 4 achievable objectives that should be given to an individual rig in a context where a "Zero Accident" workplace is the ultimate goal, but unfortunately still a concept.

Introduction

The drilling industry has evolved a lot in the last forty years, not only from a technological point of view but also from an HSE point of view. Nowadays, it is a common practice to drill extended reach wells or long horizontal drains navigated in thin reservoirs with high accuracy, not even talking about exotic trajectories necessary to drill on congested declining fields; however, an equally impressive progress was made on the protection of the workforce, thanks to the change of mentality and the ever growing legal environment. A 21st century drilling site, whether offshore or onshore, has nothing to do with what used to be the standard forty years ago: the impact on the environment is taken care of right at the pre-engineering phase and the protection of personnel on-site during the whole life of the drilling project is of highest importance.
A New Approach for Field Surveillance: Enhanced Monitoring Associating Smart Alarms to Produce More Oil
Authors: Lentini A. , Fumia G. , Malonga H. , Okassa F. , Le Cann J. P. , Lessi J.
Published: December 2007

The management of producing wells activated with ESP pumps has to take into account several problems: limited pump run life, production losses due to multi ESP failure and shut in wells.

Monitoring of production and pump parameters is common use in the oil industry, but real time monitoring systems undoubtedly provide operators with the possibility of improvements of production conditions because the easy and rapid access to data allows engineers to plan effective and timely remedial jobs.

This paper is a case history of a field test performed in an unmanned platform of a brown field with producing wells activated by electrical submersible pumps and shows the advantages related to the application of this innovative technology in terms of early diagnosis and problem solution.

The methodology includes the following sequential stages: Design and installation of an ad hoc surveillance system with remote control and Multiphase Meter;Monitoring of several flow periods to identify different well behaviors: Stable flow, Anomalous Flow and No flow conditions. On the basis of stable flow conditions, the regular behavior is set using the well and pump performance;Identification of the base line reference values for the 2 main parameters (Tubing head pressure and Current) during different well behaviors;Smart Alarms Setting to detect abnormal behavior and identify related problems. The smart alarms status can then be directly sent to field production supervisors and decision makers.

The pilot duration was 3 months long and the benefits directly related to the application of the Smart Alarms system were the following: oil production increase ≈ 10% − 20%production losses avoided ≈ 1500reduction of OPEX in terms of savings ≈ 1,000 K€pump run life increase not quantified due the test's short duration

The advanced information provided to the decision makers brought additional benefits to oil company leading to early production recovery, improvement of well inflow and outflow performance knowledge.

The Smart Alarms approach can be also applied to other well typologies and data sources.
Phase Behavior Study of Hydrocarbon/Water/Methanol Mixtures at Reservoir Conditions
Authors: Bang V. , Pope G. A. , Sharma M. M.
Published: December 2007

This paper presents a study of gas condensate hydrocarbon mixtures and the effect of water, methanol and isopropanol on phase behavior. Very little data is available on the phase behavior of hydrocarbon-water-methanol mixtures at the high temperatures typical of these reservoirs. Such data are needed for compositional reservoir simulations of well treatments to optimize the performance of solvent treatments of blocked wells. Constant composition expansion experiments were performed to measure the phase behavior of hydrocarbons-water-methanol mixtures up to 300 °F. The effects of temperature, pressure and water and methanol concentration on the phase behavior were measured. The Peng-Robinson equation-of-state was used to model hydrocarbon-water-methanol mixtures. The binary interaction parameters were tuned to fit the data and found to show a linear variation with temperature. The binary interaction parameters and temperature-dependent volume shift parameters are the key parameters to model these complex polar mixtures. Both the classical van-der-Waals and the Huron-Vidal mixing rules were used and found to give good agreement with the data. Phase behavior experiments performed on hydrocarbon-water-isopropanol mixtures showed that isopropanol decreases the aqueous phase volume fraction and increases the liquid hydrocarbon phase volume fraction compared to the analogous hydrocarbon-water-methanol mixtures. These data are needed to predict the conditions under which methanol/isopropanol treatments can be successfully applied in gas wells to remove water and condensate blockage.
Optimizing Oil and Gas Production by Intelligent Technology
Authors: Zhu D. , Furui K.
Published: December 2007

Intelligent completion technology, namely permanent downhole monitoring and flow control devices that allow continuous monitoring and control of well flowing system, has become more and more popular today in oil and gas wells to assist well and reservoir performance management. The applications of intelligent well today are much beyond the original vision of the technology that measurement and control become possible without intervention and their associated costs by installing permanent downhole monitoring and flow control devices connected to the surface. In addition to these advantages, the technology has been used to optimize gas lift and ESP systems, sand control, formation damage control, water breakthrough, gas coning problems, and crossflow eliminations.

This paper summarizes the current available intelligent technology, describes the production optimization workflow process from data acquisition to optimization and control, and focuses on a discussion of the effective approach of deploying the technology for different types of well completions and drainage volume characteristics. The majority of previous publications on intelligent completion technology have been in two areas: (1) identification of well production problems; and (2) control of the well flowing system to meet operational constraints and limits and/or improve existing well performance to higher levels. Many field examples showed that the monitoring function and the control function of intelligent completions have been applied independently. The efficiency of the integrated system could be greatly improved if monitoring and control systems are interactively integrated. Monitoring can directly guide control schemes and validate the results of their executions. The examples in the paper show that with simple interpretation of monitored data, control of well operation can be less time consuming and more effective. Likewise, downhole monitoring needs to be used with control systems so that the problems identified by monitoring systems can be treated accordingly. The approaches presented in the paper will help to maximize the value of intelligent completion.
Implementing an Undergraduate Minor in Energy
Authors: Fanchi J. R.
Published: December 2007

A problem facing society today is the need to develop and implement a strategy that will provide energy to meet future global energy needs and satisfy environmental objectives. The future energy industry is expected to rely on a variety of energy sources ranging from fossil and nuclear energy to renewable energy. Most undergraduate technical programs result in educational specialization that makes it difficult for students in a particular technical major to appreciate the role of their specialty in either a broad technical or societal context. An undergraduate energy minor can expose undergraduate students to all of the energy options that may be encountered in the 21st century energy mix. The purpose of this paper is to describe the implementation of an undergraduate minor in energy.
New Approach to Simulating Multicomponent Fluids Flow to Hydraulic Fractured Well
Authors: Dinariev O. , Shandrygin A. , Rudenko D. , Tertychyi V. , Evseev N. , Klemin D.
Published: December 2007

High accurate reservoir simulation is required to better describe multiphase fluids flow to hydraulic fractured wells and improve the development of gas-condensate field. In recent years, numerous research efforts were focused on the developing efficient numerical scheme for full-field simulation and have been facing the problem of tremendous computational resources used to simulate realistic hydraulic fracture details for better and more reliable production optimization. Most of the existent numerical models are based on 3D computational grid that is used for the whole reservoir with grid refining in fracture domain and couldn't completely account all phenomenon within reasonable computational time.

New approach for simulation of multiphase multicomponent steady state flow around the hydraulic fractured well is proposed. The approach is based on the splitting the thermodynamic and hydrodynamic problems of multiphase and multicomponent fluids flow. It is also assumed that conductive fracture could be described by 2D surface in 3D permeable formation. Additional coordinate system inside fracture allows to simulate the heterogeneous internal structure of fracture and account the details of the exchange process between fracture and reservoir. Relative permeability and non-Darcy effects in fracture and formation and non-uniform fracture conductivity could be taken account as well.

Proposed model can be used for simulation of the steady-state multiphase multicomponent flow to hydraulic fracture of any arbitrary shape. Excellent agreement with commercial dynamic simulators was achieved for gas condensate flows simulation. Significant decrease in computational time in comparison with the existent simulators had been achieved.
An Empirical Model for Predicting Crude Sludging Potential Caused by Acidizing
Authors: Garrouch A. A. , Malallah A. H. , Al-Enizy M. M.
Published: December 2007

Acid stimulation experimental data collected on 231 crude samples from various oil fields were used in this study to formulate an empirical model for quantifying the amount of asphaltic sludge precipitating as a consequence of an acidizing job. Data showing the individual effects of acid strength, acid type, solvent preflush, iron control additives, ferrous and ferric ion concentrations, mutual solvent concentration, corrosion inhibitor type, and surfactant types have been used as the basis for formulating an empirical model for the weight percent of asphaltene sludge. The acid-induced sludge model has been validated with stimulation data from the Endicott field. The model is then used to study the effect of various factors on sludging.

A 15% HCL concentration is confirmed to be the threshold for serious acid-induced sludge. Hydrofluoric acid exhacerbates sludging except at low concentrations less than 3%. Asphaltene sludging is promoted by the presence of ferrous and ferric ions. Ferric ions cause more sludging. The addition of iron control additives like citric acid, EDTA, and NTA is found to cause sludging. Erythorbic extractant causes less sludging than any of the iron control additives commonly used. The three surfactant types investigated (Fluoro-surfactant, Non-emulsifier, wetting agent) are found to have an identical effect on sludging. The use of a mutual solvent concentration greater than 5% is found to increase the sludging tendency.

Acid-induced asphaltene sludging is becoming an increasing cause of oil well stimulation treatment failure. The proposed model predicts quantitatively the effect of various acid additives on crude oil sludging, and may be used as a designing tool for an acidizing job with minimum sludging potential.
A New Approach for Field Surveillance: Enhanced Monitoring Associating Smart Alarms To Produce More Oil
Authors: Lentini A. , Fumia G. , Malonga H. , Okassa F. , Le Cann J. P. , Lessi J.
Published: December 2007

The management of producing wells activated with ESP pumps has to take into account several problems: limited pump run life, production losses due to multi ESP failure and shut in wells.

Monitoring of production and pump parameters is common use in the oil industry, but real time monitoring systems undoubtedly provide operators with the possibility of improvements of production conditions because the easy and rapid access to data allows engineers to plan effective and timely remedial jobs.

This paper is a case history of a field test performed in an unmanned platform of a brown field with producing wells activated by electrical submersible pumps and shows the advantages related to the application of this innovative technology in terms of early diagnosis and problem solution.

The methodology includes the following sequential stages:

Design and installation of an ad hoc surveillance system with remote control and Multiphase Meter; Monitoring of several flow periods to identify different well behaviors: Stable flow, Anomalous Flow and No flow conditions. On the basis of stable flow conditions, the regular behavior is set using the well and pump performance; Identification of the base line reference values for the 2 main parameters (Tubing head pressure and Current) during different well behaviors; Smart Alarms Setting to detect abnormal behavior and identify related problems. The smart alarms status can then be directly sent to field production supervisors and decision makers.

The pilot duration was 3 months long and the benefits directly related to the application of the Smart Alarms system were the following:

oil production increase          ≈ 10%-20% production losses avoided        ≈ 1500 m3 reduction of OPEX in terms of savings    ≈ 1,000 K€ pump run life increase not quantified due the test's short duration

The advanced information provided to the decision makers brought additional benefits to oil company leading to early production recovery, improvement of well inflow and outflow performance knowledge.

The Smart Alarms approach can be also applied to other well typologies and data sources.
History Matching Using Face-Recognition Technique Based on Principal Component Analysis
Authors: Yadav S.
Published: December 2007

This paper presents a novel methodology of history matching using the face recognition technique based on Principal Component Analysis, which is currently used in computer vision applications. During history matching the spatial reservoir parameters at grid blocks are adjusted in order to obtain a simulated response close to the observed response. This implies that the optimization problem can be prohibitively large and inefficient.

In order to circumvent this problem, a set of multiple geologically plausible permeability realizations or the training images for a given depositional environment are obtained. These realizations could be quite different, yet they are not completely random. In spite of their differences, there are characteristic geological patterns, which occur in theses realizations. Such patterns could be extracted out by means of a mathematical tool called Principal Component Analysis. These characteristic geological patterns can then be combined in different combinations to obtain the new plausible realization. The goal is then to find the weights used to combine the characteristic geological patterns such that difference in the historical data and the simulated response is reduced. Therefore the history matching problem is now reduced to optimization problem in a much smaller parameter space. The number of parameters to be optimized is reduced to the number of dominating geological patterns present. The new realization is automatically constrained to the given geological environment since it is a combination of its characteristic features. Also this approach can depict patterns of geological continuity consisting of strongly connected, curvi-linear geological objects such as channels or fractures, unlike the variogram based two-point statistical covariance models.

This approach mimics the "face recognition" or the "voice recognition" technique, which are already being successfully applied in their respective domains. The proposed technique has been successfully tested in a fluvial depositional environment.
Robust and Efficient Simulation of Formation-Tester Measurements with a Rigorous Compositional Simulation Code
Authors: Malik M. , Torres-Verdín C. , Sepehrnoori K.
Published: December 2007

This paper describes the development, testing, and successful application of a new compositional code for the numerical simulation of oil-base mud invasion and formation tester measurements that involve arbitrary miscibility between oil-base mud and native oil. The simulator assumes axial-symmetric variations of petrophysical properties as well as axial-symmetric flow-rate sources and boundary conditions. However, there are no restricting assumptions to the degree of miscibility between the fluids involved in the simulations. We solve the time-space evolution of component concentration with a time-marching implicit pressure explicit concentration (IMPEC) scheme. This method of solution considers the complete equations of state and implements rigorous and efficient flash calculations to describe the thermo-dynamical evolution of the various compositional phases due to space-time variations of pressure and concentration.

Simulations described in this paper consider the process of oil-base mud-filtrate invasion into reservoirs containing mixtures of connate water and oil. Subsequently, we simulate formation tester measurements by enforcing fluid withdrawal through the dual-packer section of the tester. Measurements consist of fluid pressure, fractional flow rates, fluid density, and fluid viscosity. Examples of application include homogenous and multi-layer formations as well as a capillary-transition zone. Comparison of simulation results against those obtained with a commercial code confirms the efficiency, accuracy, and reliability of our simulator.

Sensitivity analysis indicate that time evolution of fractional flow rates, fluid density, and fluid viscosity measured with the formation tester remain influenced by the petrophysical properties of the formation as well as by relative permeability and capillary pressure. The simulations described in this paper accurately predict the measurement times necessary for the acquisition of clean samples of native formation oil in the presence of invasion and heterogeneous spatial distributions of petrophysical and rock-fluid properties.
History Matching with an Uncertain Geological Scenario
Authors: Suzuki S. , Caers J.
Published: December 2007

With the increased emphasis on accurately representing geological variability / uncertainty in modeling heterogeneous reservoirs, the goal of modern history matching methods is not only to reproduce the past production behavior; it also aims at preserving geological realism. However, in complex geological environments, with limited access to the subsurface (e.g. deepwater/turbidite systems), the geological scenario governing the spatial distribution of important reservoir properties such as facies type / permeability is uncertain. Indeed, with few wells and limited seismic resolution, an accurate determination of the geological depositional system may not be possible. In this paper, we propose a new history matching technique that can account for this first order uncertainty. At the same time, this method can be regarded as a way to reduce geological uncertainty by means of production data.

To model geological scenario uncertainty we rely on the field of multiple-point geostatistics, where each scenario is quantitatively depicted by a training image, a fully explicit reservoir analog of sorts. Given a training image, a geological model realization can be stochastically generated using geostatistical algorithms. A discrete set of such scenarios is assumed available from a careful geological uncertainty study. To solve the inverse problem of history matching one can no longer rely on the classical optimization with gradient formulation, due to the inherently discrete nature of the problem. Instead, we rely on stochastic search methods (such as the Neighborhood Algorithm), that search in the space of all geologically plausible model realizations for those that history match by considering a ‘similarity’ measure between such plausible geological model realizations. We show that the production response in the space defined by a suitable similarity measure is structured, i.e. not random, hence optimization/history matching with stochastic search methods is effective. Several realistic synthetic reservoir applications are presented to illustrate this methodology.
Onshore LNG Production Process Selection
Authors: Mokhatab S. , Economides M. J.
Published: December 2007

The refrigeration and liquefaction process is the key element of a liquid natural gas (LNG) project and for most estimates of under construction or contemplated projects it can consume about 35% of the capital expenditure and up to 50% of the subsequent operating costs. The latest figures by the time of this writing showed that the world liquefaction capacity was 17 Bcf/d, slated to increase to 41 Bcf/d by 2010. There are several different licensed processes available with varying degrees of application and experience. This paper presents a critical overview of the LNG process and an analysis of the main methods available for the liquefaction of natural gas in an onshore LNG plant. The paper also discusses selection issues relating to the main technologies that affect LNG plant configuration.
Optimizing Drilling Performance in Salym—The Best Of Russia Meets the Best of the West
Authors: Koole Koos
Published: December 2007

Salym Petroleum Development (SPD), a 50/50 joint venture between Shell Salym Development and Evikhon, has been developing the Salym group of oilfields in the heartlands of Western Siberia since September 2003.

Before drilling operations started in April 2004, the Russian well construction practices, materials and drilling equipment were studied. The study lasted for about one year and involved frequent site visits to Siberia. Based on the findings a well construction strategy was developed, that is based largely on Russian well construction materials, top end Russian drilling equipment, such as the Uralmash BU 3900 and 4500 drilling rigs, and Russian Oil field services, and combines them with those Western services and equipment that offer a clear advantage on overall drilling performance. Examples are utilization of Western topdrives, solids control equipment and performance downhole motors and MWD systems.

The rigs are operating on day rate contracts, with the SPD well engineering department driving the operational and HSE performance through the strict application of the Shell Trademarked "Drilling the Limit" performance process.

After 2 years of drilling it has become clear that this carefully selected well construction strategy brought SPD best in class drilling and HSE performance.
A New Method for Improving LWD Logging Depth
Authors: Chia C. R. , Laastad H. , Kostin A. , Hjortland F. , Bordakov G.
Published: December 2007

This paper will describe a new method for improving Logging While Drilling (LWD) depth accuracy. Case studies that describe this technique will also be presented. It is generally accepted that using the Drillers depth measurement for LWD applications has been the most practical solution to a complex depth problem. The various sources of depth errors have also been described and quantified in the industry. Two of the main contributors to drillpipe based depth error are mechanical stretch and thermal expansion. Of these, the mechanical stretch is governed largely by the well profile, linear weight of the pipe, and the frictional forces that can be calculated using industry standard torque and drag calculations. The coefficient of linear thermal expansion of the drillstring components and the distributed temperature of the drillstring assembly at the time of measurement govern the change in length due to temperature. To compensate for these effects requires a series of algorithms that identify the mechanical condition of the drillstring at the time of measurement based on the operational drilling mode. Then, a standard torque and drag model is used to calculate the mechanical stretch, and a thermal expansion algorithm subsequently applies the temperature component of the depth correction. The results of these computations are a corrected logging depth, and an improved time to depth conversion file that can be used to recalculate the logging data. The results from case study data strongly support that; uncorrected standard LWD depth accuracy today is often at least as good as that provided by comparable wireline logs; and that LWD depth can be significantly improved using this technique. This new method for improving logging depth will lead to enhanced single well evaluation and the improved well-to-well correlation of reservoir features, and hence the value of the reservoir model.
Enhancing Well Productivity After Hydraulic Fracturing in the Priobskoe Oilfield
Authors: Nikurova L. F. , Surtaev V. N. , Yamilov R. R.
Published: December 2007

This paper deals with hydraulic fracture treatment issues encountered in the Priobskoye field. The focus is the determination of fracture parameters and their variation with time.

As always there are two key parameters that control the treatment effictiveness: fracture length and fracture conductivity. It is well known that, often, the actual fracture parameters are never as good as those for which the fracture is supposed to be designed for. Different reasons have been advanced in the past to explain this disparity, such as failure to fill the fracture with proppant up to the top; inefficient proppant transport into the fracture; proppant settlement by gravity; porous pack damaged with fracturing fluid gel residue. In addition, the apparent fracture paprameters may be affected by multiphase flow; non-Darcy flow; and various combinations of the above causes. Isolating the individual impact may never be possible. Despite the many approaches to describe the process of fracture design and the subsequent fluid flow in the fracture, the actual post-treatment effectiveness has not been resolved yet.

The frac job analysis remains so far an urgent issue which puts a variety of challenges to the scientific community and petroleum engineers. Understanding all the phenomena that take place in the wellbore and in the reservoir during both the fracture job and the subsequent well production would allow the selection and design of appropriate fracture parameters for an economically sound field development plan.
Drilling-Fluid Design for Challenging Wells in the Andean Mountain Region
Authors: Ramirez M. , Clapper D. , Kenny P.
Published: December 2007

Wells drilled in the Andean Mountain region of South America present significant challenges as a result of both operational and environmental factors. Wells located in the foothills along the basin are particularly difficult due tectonic stresses and unstable, probably, micro-fractured shales. Operators have experienced difficulties drilling wells using both water-based and oil-based muds (OBM). Environmental regulations hinder the use of OBM in many of those areas due to the potential environmental impact and costs associated with waste disposal. In many cases OBM has not prevented wellbore instability problems. This paper explains how a lack of understanding of regional geology and the practice of using successful drilling fluid design and drilling practices from other areas has led to wellbore problems. The water phase salinity of OBM and the use of the appropriate inhibitors in the drilling fluid play a key role in the minimization of wellbore problems. Although reactive clays are present in all the shales along the basin, they represent only 30 to 40 percent of the clay fraction, while non-expandable kaolinite clays are the major clay components. This paper explains how physical/mechanical effects are more important than inhibition in controlling these shales. Moreover, in some cases "excessive inhibition" due the presence of shale inhibitors such us potassium and high water phase salinity in OBM exacerbate the problems. Pore pressure transmission caused by fluid invasion is a major contributor to the observed problems. A combination of operational practices and improved fluid design minimizes mud and filtrate invasion. Troublesome shales in the Andean basin include, from north to south, the La Rosa and Icotetea in Venezuela, the Carbonera, Leon and Villeta in Colombia, the Napo in Ecuador, the Chonta in Peru and the Los Monos in Bolivia and Argentina. Case histories involving these shales are presented. Contrary to experiences in many other parts of the world, high water phase salinity OBM and potassium based water-based mud (WBM) are not the answer to shale stability problems. Rather, mud sealing properties, correct chemical composition and appropriate drilling practices are the key factors in maintaining wellbore stability.
Means for Passive Inflow Control Upon Gas Breakthrough
Authors: Crow S. L. , Coronado M. P. , Mody R. K.
Published: December 2007

Generally, horizontally completed oil producers are susceptible to localized gas coning during their life due to the gas/oil contact encroaching the well bore. Even a small difference in permeability and/or relative permeability along the well bore can result in gas coning, which impacts oil production and gas handling issues. Production optimization can be achieved by selectively shutting in areas where gas coning has broken into the wellbore, thus improving drainage efficiency.

A new system has been developed to passively sense gas inflow into the well. Once gas is detected in sufficient levels a valve is activated which shuts off the flow path into the well. The valve is designed to detect fluid density changes, and will activate once a predetermined decrease in production fluid density is reached, indicating gas coning. Incorporated in a sand face screen completion, each screen joint includes a phase-sensitive valve that enables it to work independently of the others. This approach has the benefit of shutting off unwanted gas inflow without the need for costly well intervention. Used in conjunction with zone isolation packers to eliminate annular flow, flow normalization can be achieved across the production interval1. The design can also be adapted to shut off water flow, as well as gas, in the event of water coning into the wellbore.

This paper will detail the development process of this new passive gas shut-off valve, including laboratory testing performed to qualify the technology. Plans for full-scale two-phase flow testing, conducted in cooperation with a major North Sea operator, will also be discussed.
Impact-Fatigue Correction: Optimization on the Selection Criteria for Sucker-Rod Materials
Authors: Martínez A. , Jaimes A. , Serna J. A. , Uribe I.
Published: December 2007

In oil wells with beam pumping systems, sucker rods mainly failed by fatigue due to the fact that they operate under cycling tension stresses. Additionally, superficial defects could be generated during handling and operation of the rods, which favor the formation of fatigue cracks and consequently decreasing the original expected life of the rod. Because of a high rate of rod failures by fatigue, and the consequent increase in operational costs, a study was done to obtain experimental data that will be used for the selection and design of the sucker rods strings. Fatigue tests were done for new high strength sucker rods, selected at random in the filed, to determine the endurance fatigue limit. Four kinds of fatigue tests were done: a) the material was tested in the as received condition (normalize and tempering), b) tests were conducted with specimens having a superficial defect simulating a corrosion pit, c) same as b but samples were quenched and tempered. Material characterization was done for all tested rods, including tension, hardness and impact tests, metallographic analysis and chemical composition. The experimental results showed important fatigue differences among the material evaluated, the negative effect of the surface pitting, and the improvement of the fatigue resistance by quenching and tempering the rods. A correlation between the results of impact test, tension test and fatigue test was developed. The findings and conclusions of this study will help the design engineer in the selection process between different sucker rods in the market. Finally, a simpler test method is presented to predict the fatigue behavior between rods of similar specification but from different manufactures.
Ultralightweight and Gas Migration Slurries: An Excellent Solution for Gas Wells
Authors: Mata F. , Diaz C. , Villa Hugo
Published: December 2007

This paper shows the excellent results obtained using ultra lightweight and gas migration slurries (ULWGMS) on wells of San Joaquin and Santa Rosa fields, located in Anaco City, Eastern Venezuela.

There are several gas fields in Anaco area, with complex wells, due to their low frac gradients, pressurized water zones, depressurized gas zones, H2S and CO2 content, clay sands, and, in some cases, presence of micro fractures. These sands are also bounded by interbedded shales, with trapped gas and water, experiencing larges amount of losses of mineral oil mud, during drilling.

All these characteristics contributed to unsuccessful primary cement jobs in the past, attributed to inappropriate slurry designs, with unsuitable properties to deal with all the above factors. Statistics showed that 2 out of 3 wells in this field failed due lost circulation issues, requiring remedial cementing to address gas control, and water migration. Ultra lightweight slurries were conceived, with adequate mechanical properties (flexible and tension strengths), in addition to providing H2S and CO2 resistance.

The first 9.2 ppg ultra lightweight slurry was first used in 2003 in San Joaquin field, and indicated good isolation, by logs runned.

Subsequently, ultra lightweight slurries with densities from 9 to 11 ppg have been applied in 18 different wells in Anaco area, showing excellent zone isolation results, demonstrated by low water cut, and good bond logs.
Zonal Isolation Within Highly Fractured Carbonates in Southeastern Mexico—Special Cementing Operations
Authors: Vargas W. , Lozada M. A. , Ledesma C. E. , Caballero C.
Published: December 2007

Oil production from Southeastern Mexico mainly comes from highly fracturated carbonate reservoirs. The appropriate management of oil production, natural depletion of the reservoirs with time, and continuous upper movement of oil- water contact represent the biggest challenge to isolate properly the production zone in development wells drilled within the area.

Drilling these wells through pay zone typically requires special pressure managed drilling techniques that considers the use of Nitrogen; either as foaming agent of the base polymer drilling fluid or as two-phase component. It can allow achieving the low equivalent circulating densities needed to penetrate the depleted reservoirs. The geological complexity of the area, mainly represented by compartmentalized reservoirs delimited by multiple fractures tied to vertical heterogeneity of the production zone, comprised by limestone and dolomite separated by shaly cap rocks shows the complete picture of the final conditions of the well to be isolated.

In this paper a systematic approach is presented, not only to highlight the use of ultra-light cement slurries1, but to remark pre-planning, well preparation, downhole tools, equipment and techniques used for cement placement to achieve zonal isolation within target intervals and/or oil-water contact. The main challenge remains the ability to properly isolate intervals that present washouts of more than three times the nominal external diameter of the bit. Also, the omnipresence of very low pore pressures, as low a 0.30 g/cm3 (2.5 lb/gal) of equivalent circulating density.

Therefore, here are presented the different slurry types used to perform these special cementing jobs, and also the operating procedures used by the cement placement techniques. Several examples have been selected to support the effectiveness of the applied methodology. Even though examples are related to a particular location and circumstances within Southeastern Mexico, the designed slurries and placement techniques can be customized to be applied successfully in similar areas.
Modeling Nonisothermal Rapid Multiphase Flow in Wells Under Nonequilibrium Conditions
Authors: Michel G. , Civan F.
Published: December 2007

An improved non-isothermal mathematical model considering the non-equilibrium effects involved during rapid multiphase flow in wells is presented. The extent of the non-equilibrium effect on deviation from the equilibrium model predictions is delineated at various flow rates, fluid saturations, and temperatures. Applications for three-phase (oil/water/gas) systems are presented. The model presented here can be coupled with reservoir simulation for accurate representation of the well-fluid hydraulics under non-equilibrium and non-isothermal flow conditions.
New Modified Black-Oil Correlations for Gas Condensate and Volatile Oil Fluids
Authors: El-Banbi A. H. , Fattah K. A. , Sayyouh M. H.
Published: December 2007

Several authors have shown the applicability of modified black oil (MBO) approach for modeling gas condensate and volatile oil reservoirs. It was shown before that MBO could adequately replace compositional simulation in many applications. In this work, a new set of MBO PVT correlations was developed. The four PVT functions (oil-gas ratio, Rv, solution gas-oil ratio, Rs, oil formation volume factor, Bo, and gas formation volume factor, Bg) were investigated. According to our knowledge, no other correlation for calculating oil-gas ratio exists in the petroleum literature. Alternatively, oil-gas ratio (needed for material balance and reservoir simulation calculations of gas condensate and volatile oil reservoirs) had to be generated from a combination of laboratory experiments and elaborate calculation procedures using EOS models. In previous work, we found that Whitson and Torp method for generating Modified Black Oil (MBO) PVT properties yielded best results when compared with compositional simulation. This method (and the others available in the literature such as Coats’ and Walsh's) requires the use of data from PVT laboratory experiments and proper construction of EOS models. We used Whitson and Torp's method to generate our database of the MBO PVT curves used in developing our correlations after matching the PVT experimental results with an EOS model. For each one of the four PVT parameters, we used 1850 values obtained from PVT analysis of eight gas condensate fluid samples and 1180 values obtained from PVT analysis of five volatile oil fluid samples. The samples were selected to cover a wide range of fluid composition, condensate yield, reservoir temperature, and pressure. The data points were generated by extracting the PVT properties of each sample at six different separator conditions. We then used multi-variable regression techniques to calculate our correlation constants.

The new correlations were validated using the generalized material balance equation calculations with data generated from a compositional reservoir simulator.

These new correlations depend only on readily available parameters in the field and can have wide applications when representative fluid samples are not available.