bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Neural Network System for Casing Collapse Occurrence and Its Depth Prediction in a Middle-Eastern Carbonate Field
Authors: Salehi S. , Hareland G. , Ganji M. , Dehkordi Keivan Khademi , Abdollahi M.
Published: December 2007

A large carbonate oil field in Iran is suffering from severe casing collapses. 48 casing collapses have been found to be reservoir compaction and poro-elastic effects and corrosion.

The application of neural networks for predicting casing collapses using complex multi-dimensional field data has been undertaken. This paper shows how a neural network (ANN) system can be trained based on the parameters affecting casing collapse to estimate the potential of collapse of wells to be drilled as well as the current wells producing in the field. The potential use of this type of analysis is large in that it can be linked as a critical risking parameter in future field development analysis. Being able to quantify the potential for collapse of a well in the future can give management the foundation for a better financial decision making on what wells and where to drill them with the potential for the larger net return on the investment. The estimated collapse and corresponding depth could also benefit in the type of casing design and completion method to be selected as well as workover designs. Interpretation of the neural network results, together with engineering judgment, allowed us to conclude that using this method is technically feasible for predicting casing collapses in this field.
Securing the Future in Mature Gas Fields
Authors: Schinagl Werner , Denny Mark
Published: December 2007

As North Sea gas fields become mature, significant production losses are increasingly caused by liquid loading. The reservoir energy is insufficient to transport liquid particles to surface, liquid falls back and builds up a hydrostatic column in the wellbore that balances out with the reservoir pressure, killing the well and - if nothing is done - leaving significant reserves behind.

This is, in North Sea gas fields, a relatively new problem, and is being addressed by Gas Well Deliquification, which aims to produce the liquids artificially in order to help the gas to flow unobstructed again. The major challenge however, is to find a suitable artificial lifting technology, as most artificial lifting technologies work well with liquid, but cannot handle free gas. A further challenge is to make the existing onshore technologies fit for use in environments that require the use of a SSSV (offshore).

This paper addresses the phenomenon of liquid loading, and presents various technologies that are currently being worked-on to be implemented in North Sea gas fields. Moreover the paper shows the results of the first sets of very promising batch surfactant trials in Southern North Sea fields which were a breakthrough in offshore surfactant application. Moreover it discusses a state-of-the art multiphase pumping method that is being trialled in an onshore oil field, but has significant opportunity for gas well deliquification. Another focus will be on the planned use of "combination methods" that combine the benefits of various artificial lifting technologies in one system, and should be able to produce liquid loaded wells until they are fully depleted.

Applying these deliquification technologies will lead to higher gas production rates in the short-term and extended field lives until wells are fully depleted, in this way securing the future of gas supplies from mature gas assets.
Implicit 1D Transport Solvers for a Streamline Simulator for Fractured Reservoirs
Authors: Andrianov Nikolay , Bratvedt Kyrre , Myasnikov Artyom
Published: December 2007

Naturally fractured reservoirs can be seen as a set of low permeability matrix rock blocks and a high permeability network of fracture channels. This representation is conventionally described by a dual porosity model, which is the one used in the present work. More precisely, the porosities and absolute permeabilities at each point of a reservoir are considered to be those of two interpenetrating continua, the matrix and the fractures one. It is also assumed that the flow occurs in fractures only, i.e., the matrix permeability is equal to zero. Mass transfer between matrix and fractures is modeled by empirically determined transfer functions.

Fracture permeabilities can differ in orders of magnitude, which results in very different flow velocities in different parts of the reservoir. This circumstance is advantageous for simulating the reservoir numerically with the streamline method [1,4,6,7,8,9,11,17,18,21]. Indeed, in the streamline method the transport part is solved along a set of onedimensional streamlines, and the corresponding time step used for the update of the solution can be chosen independently for each streamline. Therefore, there is no global time step restriction, which is the case for finite difference simulation.

This work is a further development of methods, proposed in [19,16] and [2]. We are concerned with the efficient solution of saturation transport along streamlines. To this end, we propose to use an implicit method. This eliminates the CFL restriction on the time step which is inherent to explicit methods, at the price of possibly introducing more numerical diffusion. The numerical method can be further accelerated with the use of adaptive mesh refinement along streamlines [2]. We show that the proposed technique can be useful when one needs to estimate the flow pattern in the reservoir quickly, e.g., for ranking of geological models.
Integrating Production Operations and Economics Under Uncertain Conditions
Authors: Saputelli L. , Mijares G. , Rodriguez J. A. , Deaton D. , Sankaran S.
Published: December 2007

The high oil prices of the last five years have motivated operators to unveil less historically attractive hydrocarbon resources and to optimize production operations from existing fields. In fact, many operators of brown and mature fields around the globe plan increases in production of more than 100% during the next five years.

Optimizing production operations may — with the minimum effort— involve identifying opportunities for production increases from reservoirs, from individual wells, and from surface equipment. In addition, to sustain lean operations, production operations will require constant review of processes, management systems, adaptation of people, and applications of smart technology.

Often, decisions must be made despite uncertainties of well performance, subsurface response, equipment failure rates, and downstream demands. The heterogeneity of information and the complexity of current assets imply an iterative approach to identify viable opportunities. Opportunities require management of risk and uncertainty.

To accomplish such a challenging goal, it is necessary to estimate new capital investments for wells and facilities while considering both reservoir uncertainties and multiple scenarios for development. New capital investments are intended to increase the economic value of daily production operations.

We present a structured methodology for integrating reservoir forecasts with wells and with surface facilities and operational issues. We also present several case-studies. Operational issues include well performance, subsurface response, equipment failure rate, and downstream demands. The methodology considers the integration of reservoir production uncertainty, well performance, drilling schedule compliance, workover success, and varying surface facility variables, such as availability, uptime, and capacities.
Streamline Simulation With an API Tracking Option
Authors: Beraldo V. T. , Blunt M. J. , Schiozer D. J. , Qi R.
Published: December 2007

There are several offshore oil fields where vertical and horizontal density variations can be found. In order to study this type of reservoir, conventional Black-Oil simulators with an option called API Tracking have been used. This option allows one to define a three-dimensional oil density distribution at the beginning of the simulation and track its variations due movement of oil in the reservoir.

Streamline-based simulators can be much faster than conventional finite difference simulators when applied to large and heterogeneous models, which are exactly the most likely to have initial oil property variations. However, current streamline simulators don't have the API Tracking option and can only consider oil with uniform gravity throughout the reservoir.

In this work, a 3D incompressible streamline simulator has been modified in order to model oil composition variations, like conventional simulators with API Tracking, keeping the advantages of the streamline method. Mathematically, this option is similar to considering miscible gas injection; this method could also be used to study injection and geological storage of CO2, for instance.

To validate this work, comparisons were made between streamline and grid-based simulators. We analyzed saturation distributions and simulation run time using a fine-grid reservoir description, based on the SPE 10 model that represents a North Sea field. The results showed that API tracking can be used with streamline simulators with all the advantages of the method, including reduced run time in relation to conventional simulation, while giving similar results.
Geosteering in Umm Gudair Field With Simultaneous Density and Resistivity Images in Real Time (First Time in the World)
Authors: Gohain Ashis Kumar , Al-Anzi Nayef Abdullah , Archibong Ekpo Ita , Jawad Waleed Ahmed
Published: December 2007

The Umm Gudair (UG) Field is located in West Kuwait and is managed by Kuwait Oil Company (KOC). With the aim of draining oil from the undrained northern flank of the west UG area, KOC decided to drill UG-132H, an openhole horizontal producer.

UG-132H was chosen as the replacement well for an abandoned well. Located in the northern flank of the field, UG-132H was placed approximately 450 m west of the abandoned well. The lateral drain hole objective of keeping the well at a minimum of 65 ft above the oil/water contact was achieved.

Executing this strategic well required careful selection of casing programs, drilling tools, services, and teamwork from all departments to keep the well within the desired target. To achieve the objectives, the KOC team decided to utilize an advanced proprietary rotary steerable system, logging while drilling (LWD) Imaging technology and the geosteering services to properly place the well within the reservoir. The steerable System enabled smooth and timely drilling of the drain hole. This resulted in a smooth and in-gauge borehole, hence producing a favourable environment for acquiring good quality real-time images for accurate structural dip determination and well placement.

This paper will focus on the well profile, and the benefits of the advanced rotary steerable system for the long drain hole section. It will also highlight the complementary nature of transmitting both the density image and resistivity image in real time to enable accurate steering decisions. It will also show how the LWD images were useful in characterizing the different facies within the reservoir.
Internal Erosion in Rocks During Produced and Seawater Injection
Authors: Bedrikovetsky P. , Furtado C. A. , de Souza A. L. S. , Siqueira F. D.
Published: December 2007

Diagnosis of formation damage mechanism allows choosing the right damage removal technology during seawater injection and Produced Water Re-Injection (PWRI). Reliable prediction of injectivity decline is essential for planning of well stimulation, fracturing, etc.

Usually the stabilisation of well injectivity index after decline is explained by erosion of external filter cake, or by warm holes or even by fracture opening. Nevertheless, the stabilisation is observed in corefloods, which evidences internal erosion. So, particle deposit erosion must be considered to interpret the injectivity stabilisation. The particle erosion was described by introduction of a new particle storage capacity function which is equal to maximum retained concentration versus dimensionless flow velocity. After the maximum is reached by the retained concentration, particle capture does not happen any more. The particle storage capacity function is a reological characteristic that closes system of governing equations.

The coreflood by suspension with permeability stabilisation was performed with a constant injection rate. Pressure drop on the core and rate have been measured during the flooding. The analytical model developed allows to perfectly match the experimental impedance curve and calculate from it three injectivity damage parameters – filtration and formation damage coefficients, and also the maximum retention concentration. The obtained values of filtration and formation damage coefficients are in the usual variation range for these coefficients.

Introduction of just one new parameter – maximum retained concentration – into a classical suspension filtration model allows for significant enrichment of the physics schema for suspension transport and retention. An analytical model of suspension coreflood with piecewise constant rate shows that after changing the flow velocity from some value and coming back to the same value, the impedance returns to the initial constant velocity curve. It takes some time after an abrupt flux decrease to stabilise the resistance growth rate, while the resistance growth rate stabilises immediately after abrupt flux increase. If flow regime changes from low velocity to high velocity, there appears a short particle pulse at the outlet; it does not happen when velocity changes from high value to low value.
Fast and Efficient Modeling and Conditioning of Naturally Fractured Reservoir Models Using Static and Dynamic Data
Authors: Garcia M. , Gouth F. , Gosselin O.
Published: December 2007

A large proportion of petroleum reservoirs is known to be naturally fractured with consequences on their flow behavior hence on reservoir performance. Though the modeling of such reservoirs has been the purpose of many research works, it remains a challenging task. Too simplistic reservoir models do not allow capturing essential features like large-scale fracturing trends, or non-linear multivariate relationships between the equivalent (generally anisotropic) permeability of the fracture system, and fracture densities and properties to be characterized on a directional fracture-set basis. Conversely, too complex reservoir models, intended to be more realistic, require computationally intensive and memory consuming algorithms. They also involve numerous parameters, a large part of which cannot be estimated from available data.

In-between, there is a need for reasonably complex models and methods to generate them in a consistent way with various fracturing and dynamic data in order to produce conditional models. This paper presents such an approach, which has been developed as a workflow.

The approach is based on an original conceptual model of fracture systems and a notion of scale-dependent effective properties. It is also a two-step modeling approach in which the fracture system is first characterized, then converted into equivalent flow properties for reservoir simulation purposes. Key aspects of the approach include the geostatistical modeling of fracture densities, scale-dependent calculation of equivalent within-layer horizontal permeability tensors based on spatially periodic discrete fracture networks, analytical calculations of vertical inter-layer permeabilities, and conditioning to well-test permeabilities by using steady-state flow-based evaluation of reservoir model responses. All these aspects rely on innovative and CPU-time efficient methods. They are introduced and illustrated by case-study results.
Bit Performance Evaluation Revisited by Means of Bit Index and Formation Drillability Catalogue
Authors: Macini P. , Magagni M. , Dalt G. Da , Valente P.
Published: December 2007

The paper is aimed to calculate an innovative numerical index for bit performance evaluation called Bit Index (BI), applied on a new type of formation and bit database also known as Formation Drillability Catalogue (FDC). A dedicated research program developed by Eni E&P Div. and the University of Bologna (Italy) studied a drilling model for drill-bit performance evaluation (the BI) derived from data recorded while drilling (bit records, master log, wireline log, etc.) that includes numerical information from dull bit evaluation. This index is calculated with data collected inside the FDC, a novel classification of formations aimed to the geotechnical and geomechanical characterization and subdivisions of the formations, called Minimum Interval (MI). FDC was conceived and prepared at Eni E&P Div., and contains a large number of significant drilling parameters. Some wells have been identified inside the FDC and have been tested for bit performance evaluation. The values of BI are calculated for each bit run and are compared with the values of the cost per meter. The case study analyzes bits of the same typology and run in the same formation. The BI methodology implemented on MI classification of FDC can improve consistently the bit performances evaluation, and it helps to identify the best performer bits. Moreover, FDC turned out to be particularly functional to BI, since it discloses and organizes many formation details that are not easily detectable or usable from bit records or master logs, allowing for targeted bit performance evaluations. At this stage of development, the BI methodology proved to be economic and reliable, helping as well to make drill bit selection less erroneous and more logical.
Successful Installation of Stand Alone Sand Screen in more than 200 Wells—The Importance of Screen Selection Process and Fluid Qualification
Authors: Mathisen A. M. , Aastveit G. L. , Alterås E.
Published: December 2007

Effective sand control and high well productivity throughout the life of the well have been defined as success criteria for the use of Stand Alone Screen as sand control strategy.This paper describes the strategy to meet these success criteria and illustrates the experience in Hydro Oil & Energy to date.

A recommended practice for the selection of sand control has been established based on a comprehensive screen selection and fluid qualification process. The method includes testing and ranking of different screen designs based on sand retention and plugging properties for selected samples of reservoir sand. The screen design with the overall best performance is recommended for field application.

In addition, requirements for drilling and completion fluids have been defined.Control of particle size and particle amount in the completion fluid has been identified as the most important criteria.

Stand Alone Screen as sand control strategy have been successfully utilized for approximately 230 completions based on the presented methodology. For several of these wells, the established selection criteria published in the literature, recommended other sand control techniques to that used, e.g. open hole gravel pack. Based on Hydro Oil & Energy ‘s field experience the common practice for sand control selection applied within the industry today might be too cautious.It is concluded that Stand Alone Screen as completion method can have wider application than recognized so far.
New Methodology for AFE Estimate and Risk Assessment: Reducing Drilling Risk in an Iranian Onshore Field
Authors: Mohammad Akbari , Ravari Reza Rostami , Mahmood Amani
Published: December 2007

Because of inherent uncertainties in drilling, evaluation and estimation of well drilling time and cost are preferred to be done on the basis of probabilistic methods. The purpose of this paper is to present a new methodology for developing an AFE generating model, using a specific Iranian onshore oil field development case study to illustrate the technique. The model utilizes risk analysis and incorporates Monte Carlo simulation in conjunction with statistical analysis of historical drilling data to generate more accurate risked AFE estimates. In addition to general methodology, ROWC (rate of well completion) is introduced. The results of interpretation and statistical analysis are presented as well.
Keys to Monitoring and Surveillance for the Oil and Gas Producer
Authors: Powers John C.
Published: December 2007

This paper will contain insights and experiences from automating, monitoring, and optimizing over 7500 oil and gas wells in North America. The material will be presented in the form of a brief PowerPoint presentation and narration. There will be keen insight to the field/operations benefits. More importantly, it will outline other enterprise wide results associated with delivering field data directly to relevant back office systems for near time decision making.

The paper will delve into where these projects begin in the field and where they end with the consumers and users of the production data. There will also be key insights about how powerful the data can be once it is characterized, normalized and prepared for roll up views and management reports for quicker decision making, resource play management and production surveillance.

There will be specific descriptions of the field benefits like increased production and reduced downtime. There will also be descriptions of the back office benefits, for instance, enhancing the value of production engineers by giving him/her the tools they need to monitor and examine existing production, real time.

The conclusions will show that the oil and gas industry spends millions of dollars drilling wells and very little automating, monitoring and optimizing those same wells on a relative basis. It will also point out the grave shortage of personnel in the industry and how technology is the key to battling that issue.

The benefits of monitoring and surveillance of production are infinite (if used correctly) in the life cycle of an oil and gas asset. The examination of that data and the decisions based on that data is the key to receiving full value for the exploitation and operation of the oil and gas asset.
Swelling Packer Technology Eliminates Problems in Difficult Zonal Isolation in Tight-Gas Reservoir Completion
Authors: Antonio Luiz , Barrios Oscar , Martinez German
Published: December 2007

This paper discusses a difficult completion in which an operator required a completion that would provide zonal isolation for four different tight-gas reservoirs. Challenges included zonal isolation concerns but also drilling and cementing problems experienced in earlier wells. Previous research had determined that:

Minimum fluid contact with the rock would provide the least drilling damage and wells should be drilled with a mud with very low leak-off. Cementing could compromise completion success since formation damage could occur from cement filtrate. Since most of the wells require fracturing, good zonal isolation was essential to preventing mechanical problems and casing collapse above the fracturing packer.

Previous problems led to the investigation and adoption of a new type of packer isolation system that would achieve zonal isolation without the need for cementing, isolate the four zones, and eliminate the need for cement in the fracturing areas. The new packer design uses expanding rubber around the packer that is formulated depending on the type of mud used to expand to seal the annulus. The expansion provides the isolation required. Since this eliminates the need for cement at the fracturing zones, fracturing operations are simplified, and costs are reduced as a result of reduced rig time and materials. In addition, the expanding material will develop high differential pressure resistance that continues to increase with time.

The design procedures will be described along with how swelling packer technology was capable of providing superior sealing for the isolated zones. The operational procedures will discuss how isolation before fracture operations is accomplished, and how each zone is individually fractured successfully.
IT-Infrastructure Transformation To Support E&P Workflows
Authors: Cuzin Daniele , Rahal Dany
Published: December 2007

Exploration and production (E&P) organizations have goals to find more oil and gas reserves by increasing existing assets production and finding new assets through exploration. With the decreasing number of experts to develop and manage increasingly complex assets, new ways to operate have to be found. Workflows that allow cross-domain collaboration and real-time operations are being developed, taking advantage of powerful applications and information management best practices. As these workflows are deployed, asset groups realize that current information technology (IT) infrastructures need to be transformed to enable changes.

Defining how to transform the IT infrastructure requires understanding of the exploration, development and production domains, as well as IT expertise. The asset organization information management landscape and the underlying IT infrastructure need to be assessed in light of workflow requirements. Before starting infrastructure transformations, a vision of the future IT architecture is defined based on the organization objectives and processes. Alignment with corporate IT standards is facilitated when domain experts who also understand IT can translate E&P domain needs into IT infrastructure requirements.

Through assessments and architecture definitions performed with E&P customers we can give examples of complex IT infrastructure transformation projects that combine many IT domains such as applications, data management, security, connectivity, systems, servers, storage, and disaster recovery. Emerging IT technologies such as SOA (Services Oriented Architecture), wireless connectivity, virtualization, and high-performance computing can be leveraged and their deployment carefully planned to deliver the expected benefits. Using an IT infrastructure roadmap to guide projects will result in an IT infrastructure that works seamlessly and delivers performance, ease of use, and remote and secure data access to the asset teams.

Designing a global IT vision that leverages E&P workflows, applications understanding, and data management knowledge is an efficient methodology to gain efficiency and value from workflow optimization efforts.
A Novel Approach to Fracturing Height Control Enlarges the Candidate Pool in the Ryabchyk Formation of West Siberia's Mature Oil Fields
Authors: Yudin A. V. , Butula K. K. , Novikov Y. V.
Published: December 2007

The productive pay of the low permeability Ryabchyk formation in the mature fields of Western Siberia is separated from underlying water zones by a weak stress barrier.

Operating and service companies alike applied various techniques to prevent the breakthrough of hydraulic fractures into the underlying water zone, but so far without clear success.

The paper describes a technique of physical barrier placement and tailoring fracturing fluid systems to control fracture net pressure development, that combined is used to mitigate fracture height growth. The method consists of pumping a predetermined mixture of specialty solid materials. The case study clearly demonstrates the challenges encountered in the attempt to increase the fracture half-length in order to improve the fracture treatment and the increasingly difficult task of simultaneously controlling fracture height growth. In addition to the risk of the post-frac increase in water-cut, the uncontrolled fracture height growth into the water zone is also considered to be a major cause of premature screen-outs. This is particularly true in cases when large-mesh-size intermediate strength proppants are used.

The systematic application of the technique resulted in the increase of the average measured net pressure from 14 to 27 bars at the end of the main treatment, indicating fracture containment within the pay zone. The contained fractures manifest a 4 times liquid and 3.2 times higher average oil production compared to the production before the fracturing treatment. The new fracturing method, when compared to the conventional fractures placed in the past, resulted in the decrease the post-frac water cut from 75 to 46% while at almost no impact in average oil rate.

The paper provides a summary of the solution, which allowed the operating company to proceed with successful fracturing activity in the Ryabchyk formation.
Designing Multiple Alpha Waves for Openhole Gravel-Pack Operations
Authors: Calderon A. , de Magalhães J. V. M. , de Oliveira T. J. L. , Martins A. L.
Published: December 2007

Multiple alpha wave placement is an effective strategy to minimize operational time and risk in open hole gravel pack operations. This article deals with the adaptation of a mechanistic model, originally developed for OHGP placement, to account for flow rate variation throughout the operation. The final goal is to provide charts of flow rates versus time for a constant downhole fracture pressure. Based on these charts, a feasible pumping schedule can be proposed for each specific operation aiming time reduction and operational safety. Finally, a case study of the multiple alpha wave design is presented and its advantages highlighted.
Minimizing Drilling-Fluid Invasion in Coring Operations
Authors: Waldmann A. T. A. , Leal R. A. F. , Pires I. J. , Lomba R. F. T. , Aragão A. F. L. , Martins A. L.
Published: December 2007

Offshore Coring are time consuming and expensive operations which, if well conducted, provide extremely important information concerning rock and fluid properties. Drilling fluid invasion may be a relevant issue to affect fluid and rock reservoir original properties. Different hypothesis for pressure dissipation in the core are formulated and their impact on invasion are quantified.

This article deals with the derivation of an analytical formulation for drilling fluid invasion in cores, based on filter cake permeability results obtained in lab testing. The formulation represents the radial flow from the external lateral walls of a cylinder and considers plug flow in the porous medium and external filter cake formation. A comparison of the prediction and the observed invasion in real cores obtained in exploratory wells is presented.
Particle Trapping Sequence During Filtercake Buildup Revealed by Coloured Tracer Particles
Authors: Turekhanov Batyrzhan , Bennaceur Houria , Currie Peter K. , Wolf Karl Heinz , De Zwart Bert Rik
Published: December 2007

All water injection schemes suffer injectivity decline to some degree. It is important to understand the factors that influence the formation of an external filtercake and improve injectivity. This paper introduces a new technique for examining time-dependent particle filtration processes in a sandstone core.

Experimental work and analysis is presented of the filtration phenomena that occur during injection of water containing suspended particles into a sandstone core. The technique involves injecting a sequence of suspensions of different-coloured latex particles It gives valuable qualitative information about the processes taking place, such as the location and timing of the trapping of particles and gives quantitative predictions, by using Image Analysis and the RGB-colour system

Tests has been performed in which coloured latex particles are injected into sandstone cores. The particles form an external filtercake on the entry face of the core, and are deposited inside the core (deep-bed filtration). By switching the colour of the injected latex particles, and analysing where the different colours have been deposited, qualitative insight is gained into the process of external and internal cake forming. Using Image Analysis based on the RGB-colour system, the particle analysis can be quantified to determine effluent concentration and particle colour. Conclusions can be made about the filtration processes taking place. The conclusions are that current theories of how and when an external filtercake forms are too simple, and that external filtercake permeability for individual particles is larger than anticipated.
Enhancing Production Using Solid Expandable Tubulars in Workover Campaigns
Authors: Jennings Iain
Published: December 2007

With drilling, completion and production costs rising as fast as commodity prices, some operators are looking to optimize existing production with workover projects that turn marginal wells into significant producers. Historically, workovers have been delegated to perfunctory status even though 70% of today's oil production comes from fields 30 years or older1. Some operators relegate workover projects to strictly well repair, while others take the next step and focus on how to increase production rates. New technologies and processes have provided the impetus for these operations that are reaping compelling returns for projects that not only encompass well repair but production enhancement.

In seven years, solid expandable tubulars have gone from an unconventional idea to a viable and recognized solution for wellbore construction and integrity. The appeal of these systems lies not just in the mechanism but the functionality including the ability to deepen the hole, shut off water zones and protect zones from stimulation pressures without sacrificing hole size. Maximizing inside diameter (ID) allows the operator to use the same completion previously used in the well. Operators that have planned and used expandable systems in preventive maintenance programs have realized more attractive economic and technical results than the usual one-off workover.

This paper will explain how through a planned, multi-well workover campaign, solid expandable tubulars enhance production in an affordable manner. Case histories will be used to illustrate the planning, implementation and completion stage and the tangible results of the projects. In addition, this paper will explain how these systems provide solutions for challenging downhole conditions and situations.
Advanced Numerical Simulator To Predict Productivity for Conventional and Nonconventional Well Architecture
Authors: Pacheco Eduardo , Castro Rene , Soliman M. Y. , Flores-Avila Fernando
Published: December 2007

The production of oil and gas will continue to be the most important components of the energy industry for the next several decades. The increasing demand for hydrocarbons is moving oil-industry operators to explore all possibilities for increasing oil and gas production. This includes exploring unconventional resources and investigating unconventional well architecture. These approaches include drilling in low-permeability oil and tight-gas formations. The use of multilateral and horizontal wells has been increasing. Fracturing horizontal wells has gained significant acceptance. Multilateral wells where the various laterals have complex paths are gaining momentum as a viable way of producing hydrocarbon reservoirs.

Analytical and semi-analytical solutions for horizontal and multilaterals wells have been presented in the literature. Because of the complexity of the problem those solutions greatly simplify the problem to the extent that they are usually of limited value and application. The complexity of the actual reservoirs and well trajectory under mature conditions require more advanced solutions to realistically simulate well trajectories and well completions like acid fracturing and hydraulic fractures. Realistic simulation of complex reservoirs and wells will enable better economic analysis and decisions, provided that simulation is outstanding.

In this paper we first discuss our simulation approach that balances the goal of reaching realistic simulation while maintaining the practicality of an engineering approach. We also present several case histories of production analysis for multilaterals and horizontal wells using a robust, stable numerical simulator, multiple–block well completion and local refinements.
Modeling of External Filter-Cake Buildup in Radial Geometry
Authors: Farshbaf Zinati F. , Farajzadeh R. , Currie P. K. , Zitha P. L. J.
Published: December 2007

The problem of formation damage, i.e., permeability reduction due to injection of particulates, is a matter of interest in several engineering fields. In the previous attempts to model the external cake formation, cake thickness has been considered to be only dependent on time; even though, in practical applications the dependency of the cake profile on space can be important. In this paper a novel model has been developed to describe the steady state external filter cake thickness profile along the well-bore.A set of equations are derived from the force balance for a deposited particle on the cake surface and the volume conservation of the fluid in the well-bore. These equations are combined with the Darcy's law in radial geometry and the equation of flow in the well-bore, and solved numerically to obtain the cake thickness and fluid velocity profiles along the well-bore.
Optimum Horizontal Well Placement in Very Low Resistivity Reservoir With a Directional and Deep Logging-While-Drilling Technology
Authors: Silva A. , Cavero J. , Rodriguez W. , Augusto M. , Vargas J. , Chacon R. , Bardales A.
Published: December 2007

In the Sub-Andean basin areas of Peru, Colombia and Ecuador, important reservoir targets present very low resistivity range and also very low resistivity contrast between pay and non-pay. These unique conditions constitute a challenge in relation to the ability to map the reservoir boundaries and to allow the successful navigation of horizontal wells in thin target zones.

Conventional logging data are not able to effectively determine the approach or prevent the intersection of a reservoir limit under such reservoir conditions. Therefore, they are not perceived as the best option to optimize geosteering decision making.

A new logging while drilling technology, developed by Schlumberger, based on directional electromagnetic resistivity measurements was applied in a horizontal well, recently drilled by Pluspetrol Norte in Peru.

The service delivered directional resistivity measurement with deep depth of investigation, which allowed estimating the orientation, distance and resistivity of nearby bed boundaries. The technology was successfully used to navigate the well, optimizing the horizontal length inside the best productive zone and stay at a safe distance from the OWC. The productive behaviour of the well was better than expected.
PWRI-Induced Injectivity Decline: New Insights On In-Depth Particle Deposition Mechanisms
Authors: Rousseau D. , Hadi L. , Nabzar L.
Published: December 2007

Injectivity decline during PWRI originates not only from filter-cake build-up, but also from in-depth deposition of oil droplets or solid particles. Physical modelling of particle deposition mechanisms in porous media is thus of key interest for optimizing PWRI operations. The present work brings new insights on oil droplets and solid particle deposition mechanisms in porous media.

The experimental conditions were selected such as the ratio between pores and particle sizes is sufficiently large to ensure in-depth propagation. The parameters are: the nature of the particles injected and a Peclet number calculated on the size of the collector grains (Peg), that encompasses in a nondimensional form the impact of both flow rate and particle size.

The results are analysed in the frame of the "colloidal approach". For oil droplets and solid particles, the deposition efficiency (n) shows a transition from a behaviour in which nvaries as a power-law of Peg, with exponent values -2/3 (Diffusion Limited Deposition, DLD) to -1 (Reaction Limited Deposition, RLD), characteristic of convection-diffusion regime, to a behaviour characterized by an increase of η versus Peg, characteristic of hydrodynamic deposition regime. In the case of oil droplets (not or slightly charged), the transition occurs at a critical Peg value, Pegcgeom, corresponding to a diffusion layer thickness around the collector grain equal to the droplets diameter. In the case of electro-sterically stabilized solid particles, the transition takes place at Peg<Pegcgeom for small particles and at Peg<Pegcgeom for larger particles.
Recycling and Final Disposal of Waste Generated While Mixing Drilling and Completion Fluids
Authors: Pedraza Johanna , Serrano Mario
Published: December 2007

As the emphasis on safety and efficiency increases in the oil industry, there has been a corresponding improvement in the quality of packaging for chemical products. Examples of higher standards include plastic shrink-wrap covers, better-designed pallets, and fewer sacks loaded per pallet. These improvements in packaging, however, have led to an increase in the volume of waste generated and its disposal costs.

In order to contribute to the preservation of the environment, improve employee safety and at the same time reduce operational costs, the HES Colombian environmental team designed the Integral Waste Management System (IWMS). The IWMS provides methods for efficient waste collection, recycling and disposal. The primary focus of the system is the provision of comprehensive environmental training for field personnel to help ensure that each person is fully educated concerning the process and its objectives. Formal standards for field applications are in place. One example of rig site implementation of the IWMS includes using size and dimension appropriate color-coded containers of the appropriate sizes to transport waste materials to the stock point.

Simultaneously with the intensive training undertaken by the personnel, the IWMS incorporates an equally important process for selecting the best local companies for recycling and disposal. Those companies selected received the guidance and support necessary to obtain and maintain ISO 9000 certification, assuring the quality of the service and the internal standards expected by our customers. All the selected companies are also certified by the Environmental Minister of Colombia.

Since the beginning the IWMS implementation in Colombia, waste incineration has been reduced nearly 90%, which helps decrease environmental pollution that may contribute to global warming. The IWMS efforts have assisted with the promotion of cardboard recycling companies and similar waste management enterprises. Most importantly, the cost of drilling waste disposal in participating Colombian operations has been reduced almost 60%.
Underbalanced Drilling and Completion of Sand-Prone Tight Gas Reservoirs in Southern North Sea
Authors: Veeken C. A. M. , van Velzen J. F. G. , van den Beukel J. , Lee H. M. , Hakvoort R. G. , Hollman F. J. , Evans C. , Okkerman J. A.
Published: December 2007

This paper describes the application of underbalanced horizontal wells to develop some different tight gas reservoirs in the Netherlands section of the Southern North Sea. Underbalanced well design presented specific issues related to the nature of these reservoirs. The construction and production experience to date is evaluated and compared against similar wells drilled offshore UK. Also the benefits of the underbalanced horizontal well concept are reviewed.
Hydrocarbon Reserves and Production Increment in Laminated Sand/Shale Reservoir From 3D Resistivity Measurements, Image Logs, and Magnetic Resonance Technology
Authors: Vielma Miguel , Atlas Baker , Vandini Ricardo
Published: December 2007

Oil identification and quantification in low resistivity laminated sand-shale sequences is a major challenge for petrophysics and reservoir engineers; essentially because the thickness of the sand laminas is usually bellow the vertical resolution of the resistivity logging tool. The presence of this lithology generates electrical anisotropy where horizontal resistivity is highly affected by the conductivity of the laminar shale volume, while vertical resistivity is higher and more sensitive to the laminar sand electrical properties. Once identified the productive low resistivity problem the prediction of movable water, creates enormous uncertainty when it comes to decide if this laminated sand should be open to production in the well. All this issues have caused the underestimation of Oil-In-Situ volumes and the lost of thousands of oil production per day in the upper Misoa Formation Reservoirs in western Venezuela. The incorporation of resistive image logs in the geological analysis of upper Misoa Reservoirs, have shown the existence of thinly laminated sand-shale sequences with laminations of an inch thick and less.

Traditionally the sands with resistivity values of 20 ohm-m and above are considered as potential oil bearing reservoirs. This assumption has been made with conventional induction resistivity tools with transmitter and receiver orientation parallel to the borehole axis, therefore providing horizontal resistivity. Recently a multi-component transmitter-receiver induction tool has been used to derive both horizontal and vertical resistivity in a section of upper Misoa Formation with resistivity values in the very limit of the pay cuttof. The 3D array induction tool showed the vertical resistivity of this reservoir, to be as high as 80 ohm-m, adding up to 30 % more of oil saturation in the laminated sands. In the decision process of shooting this sands, the mobility of the water remained unknown; until, magnetic resonance measurements where included in the study. 2D analysis of T2 and diffusivity indicated that 90% of the water contained in the reservoir was irreducible, so it would not be produced.

After completing the low resistive sands, production logging tests and well production showed 1300 BBD with 4% of water. This case opened a great opportunity in western Venezuela fields where this type of lithology can be found in most of the wells drilled trough Eocene reservoirs.
Physical Model Development To Study Sand Production
Authors: González Jothsimar , Alvarellos José , González Hector , Lara Victor
Published: December 2007

Most of heavy and extra heavy crude oil reservoirs in Venezuela are non-consolidated sand deposits. Venezuelan oil industry has a great interest to produce these reserves. Cold Heavy Oil Production with Sand (CHOPS) is an alternative for the primary production of some of these deposits; in particular those where other technologies are not applicable (i.e. sands with thicknesses are less than 10 m). In general, at field level, the application of the CHOPS has been successful around the world. In particular, it has experienced great development in Canada, China and United States. The physical and numerical studies show that change in the production rates, implies cavities formation and/or erosion zones near to the well that increase reservoir permeability. In Venezuela, experience in this technology does not exist. Furthermore, the bibliographical review demonstrates that many doubts still exist on the production mechanisms. It is the reason why this work considers the design, construction and evaluation of a sand production physical model. The main objective is to study the physical processes and to evaluate the influence of different variables like pressure, flow rate, among others, in the sand production mechanisms. The obtained data, will allow the development of models to predict reservoir behavior and its properties evolution in time. This physical model is set up with a cylindrical disc, 50 cm diameter and 20 cm thickness. Cylindrical geometry guarantees radial flow. The model is instrumented with sensors to measure pressures (injection, production and pores fluid) and fluid samples are taken to quantify total sand produced. The assembly system provides facilities to apply vertical stress. Ultrasonic wave velocity measurement is used to locate erosion zones. All data is collected by a Labview card and it is processed digitally in the computer in real time. This work shows results for a preliminary test with water and mineral oil used as fluids and calibrated glass bets as the porous media. The results prove that this system can be used to study sand production mechanism but it cannot be scale up to reservoir conditions. However the results will be used to validate numerical models.