bluuebunny/crossref_metadata_2025 huggingface dataset:
SHIFTS IN POSTDISCRIMINATION GRADIENTS WITHIN A STIMULUS DIMENSION BASED ON BILATERAL FACIAL SYMMETRY
Authors: Derenne Adam
Published: December 2010

A shift in generalization gradients away from S+ and towards stimuli on the opposite end of the stimulus dimension from S‐ is a well established phenomenon in the laboratory, occurring with humans and nonhumans and with a wide range of stimuli. The phenomenon of gradient shifts has also been observed to have an analogous relationship to a variety of apparent biases in preference observed in the natural environment. One way to examine the validity of such analogies is by examining whether gradient shifts can be observed with complex and naturalistic stimuli. In the present experiment, undergraduates were trained to discriminate between faces that varied in terms of relative bilateral facial symmetry (a stimulus dimension correlated with health and attractiveness). Comparisons were made within subjects, using two sets of images. For both sets, the faces varied from naturally asymmetrical to symmetrical, and S+ was a face equidistant to the two extremes. With one set, S‐ was the naturally asymmetrical face, and with the other, S‐ was the symmetrical face. A peak shift was obtained in both conditions, although the effect was clearer in the aggregate than on the level of the individual. Overall, the results are consistent with the view that the processes responsible for gradient shifts in the lab are relevant to judgments made in the natural environment.
Development of a Methodology to Predict Solids Concentration Profile Along the Time During Pumps-off Periods
Authors: Pinto G. H. , Gandelman R. A. , Martins A. L.
Published: December 2010

One of the main functions of drilling fluids is to transport solids generated by the bit to the surface. Gelation is an important and desirable phenomenon once it avoids solids sedimentation during pumps-off periods. However, when circulation is resumed, an extra energy is required to break gel and, consequently, bottom–hole pressure peaks are observed, causing detrimental effects when fracture pressure is reached. On the other hand, gelled fluids may not avoid some heavier and/or larger particles to settle. The understanding of how particles sediment in gelled fluids is a very important task to predict solids concentration profile during and after pumps-off periods.

This work presents the development of a methodology to predict particles sedimentation in gelled fluids and pressure peaks when circulation is resumed.
Microbiologically Influenced Corrosion of Electrical-Submersible- Pumping- System Components Associated With Acid-Producing Bacteria and Sulfate- Reducing Bacteria: Case Histories
Authors: Adams D. L.
Published: December 2010

Microbiologically Influenced (Induced) Corrosion, MIC, can cause corrosion that may go unrecognized or misdiagnosed in oil production.

The end result of this corrosion phenomenon can be costly damage to down-hole equipment and other well components; leading to lost production and to premature failure of the electrical submersible pumping system (ESP) equipment, as well as other down-hole components.

A better understanding and proper diagnosis of this issue could reduce the corrosion damage and the cost associated with this corrosion phenomenon.

This paper is a presentation of case histories of this corrosion phenomenon experienced around the world.
Pore-Type Determination From Core Data Using a New Polar-Transformation Function from Hydraulic Flow Units
Authors: Rodolfo Soto B. , Arteaga Duarry , Martin Cintia , Rodriguez Freddy
Published: December 2010

A new sigmoidal function from polar transformation enables more accurate identification of pore types in fractured/vuggy reservoirs. The function is based on a polar transformation that separates the pore systems into two regions—matrix systems and fracture/vug systems—on the basis of hydraulic properties, reservoir quality index (RQI), flow-zone index (FZI), and normalized porosity. The polar transformation exhibits a hyperbolic distribution for intergranular/intercrystalline pore sample types at the point where they deviate from the trend so that we can identify pore types more accurately. Our new function has been validated from image log data from wells of Lagomar and/or Lagomedio fields and core data from different fields around the world, and we are certain that it will be of great help to the geoscientist when doing a reservoir characterization.
Hydraulic Analysis of Gas-Oil-Sand Flow in Horizontal Wells
Authors: Bello O. , Udong I. , Falcone G. , Teodoriu C.
Published: December 2010

The limited knowledge and understanding of three-phase gas-oil-sand flow behaviour and transport processes has hampered the design, safe operation and project profitability of horizontal wells deployment in unconsolidated hydrocarbon reservoirs. This work presents analytical uations for calculating pressure drop characteristics and optimal flow rate to avoid sand particles deposition and accumulation in a horizontal production well under steady state conditions. The analysis is based on multiphase transport fundamentals and mechanics of particle motion in three-phase flow. The pressure gradient results predicted by the proposed model show a satisfactory agreement with a published model. A sensitivity study is then made (after model validation) using the new model to investigate effects of operating, design and system parameters on pressure gradient and optimal transport velocity under wide-ranging conditions found in practice. The potential advantages of the new methodology are also reported.
The Marlim Field: Incorporating Time-Lapse Seismic in the Assisted History Matching
Authors: de Brito D. , de Moraes R. , Emerick A.
Published: December 2010

History matching is one of the most important and time consuming tasks in reservoir simulation. In traditional history matching approaches engineers attempt to honor production data by manually modifying their simulation models. Even though such approaches are being gradually replaced by assisted history matching methods the engineer is still responsible for choosing which simulation model parameters must be modified. On the other hand optimization algorithms available in assisted history matching tools allow changing parameter values automatically and also to consider 4D survey data in the objective function. Transmissibility multipliers associated to regions located between wells are among the most traditional simulation model parameters used for history matching purposes. Such procedure is very efficient in order to match water production data, but usually leads to transmissibility maps which have no geological meaning.

This paper describes the results of the assisted history matching study of Marlim Field, the biggest offshore field in Brazil. The assisted history matching presented here included both production and 4D seismic. The seismic information was used qualitatively and quantitatively, i.e., to delimitate regions associated to transmissibility multipliers and also in the objective function itself. The assisted 4D history matching was carried out with a commercial history matching tool, which allows the synthetic seismic calculation.

The production history data of most part of the wells was matched with similar accuracy one would expect to obtain through a careful and time consuming manual history matching approach. However the total elapsed time achieved here was orders of magnitude smaller. In addition the shape of the regions associated with model parameter values was totally supported by 4D seismic information.

It turns out even with the aid of assisted history matching tools, the quality of the results strongly depends on adequately choosing which simulation model parameters must be modified in order to match the production data. Once 4D seismic data can give a realistic picture concerning reservoir fluid replacement it can also highlight preferential permeability pathways. The results of the present study have shown these indications can be very helpful to delimitate regions with history matching purposes that have geological significance.
A New Methodology for PVT Sampling Optimization and Producibility Determination From Nuclear Magnetic Resonance
Authors: Pazos J. , Morales O. , Goddyn X. , Angel J.
Published: December 2010

The Eden Yuturi field discovered in 1996 is located in the Amazonian basin and holds several oil bearing geological units belonging to the Cretaceous. T and U sandstones are the most prolific and belong respectively to Albian and Cenomanian. They are characterized by a cyclic sequence of shales and sandstones whose deposition is driven by sea level changes. Their facies range from tidal-fluvial influenced to shallow marine. The 300 ft of U and T sands exhibit various oil qualities and compositional gradients so far poorly characterized. Another sandstone, M1 is a low resistivity pay and challenges regularly petrophysical evaluation. PetroAmazonas, in an effort to characterize the reservoir fluids and to strengthen the reservoir model, decided to initiate a sampling campaign with the EYXX well. An innovative workflow was put into place to optimize the PVT sampling and predict the producibility for reservoir. Nuclear magnetic resonance (CMR) & modular dynamic formation tester (MDT) are part of the solution put into place. NMR enables an almost immediate determination of crude oil viscosity at down hole condition to locate accurately MDT PVT bottles. CMR viscosity determination revealed, after PVT analysis delivery, been extremely accurate and validated for the whole field. Additionally magnetic resonance pore size distribution was tie in mathematically to rock types and a numeric expression of relative permeability derived, based on available core data in the field. Finally, nuclear magnetic information combined with pressure data, enabled a very accurate producibility prediction for each sands. Sampling was also successful and correlation between optical density of the optical fluid analyzer & real fluid viscosity was established. An advanced nuclear magnetic profiling was also inaugurated showing oil in the well known low resistivity M1 sands.
Reducing Formation Damage in Open Hole Standalone-Screens (OH-SAS) Completion for New Wells
Authors: Mohamad W. A. , Wahba M. A. , Jadid M.
Published: December 2010

The use of drill-in-fluid (DIF- sized salt system treated with enzyme breaker) during drilling and completion operations in the reservoir section contributed to the improvement in wellbore productivities especially desired in open hole completion where sand control using stand alone screens were applied. The mud system was designed to create a competent wellbore mud cake that was broken down by enzymes thus enabling it to flow back during production without any requirement for extensive clean-up job.

The successful application of this mud system in simplified sand control completions in newly drilled and completed wells has enabled PCSB to establish this sand control technique as an economically viable option. The high well productivity indices and the ease of well clean-up during early production has been observed in many newly completed wells with OH- SAS completions.

The early success of this sand control philosophy with the use of DIF for drilling the reservoir section, is indicated by sustained production of 7,000-8,000 bopd from the two wells in an oil field since early 2007. The high productivity indices of over 100 bpd/psi has enabled the wells to be produced at low drawdown pressures thereby preventing slumping and production of sand onto the screen. This can be concluded from the continuing high flowing tubing head pressures in both wells.

This paper highlights the successful use of DIF in contributing to the much improved well productivities giving some highlights of the production performances of the wells completed with OH-SAS to date compared with cased hole gravel packed (CHGP) wells as was previously practiced.
An Equation to Predict Two-Phase Relative Permeability Curves in Fractures
Authors: Chimá A. , Chávez E. , Calderón Z.
Published: December 2010

E. S. Romm in 1966 (Romm 1966) proposed an equation to calculate the relative permeability curves in fractured systems based on experimental results. His research concluded that relative permeability is a linear function of saturation (krw = Sw, krnw=Snw). Currently most fractured reservoir simulators use E. S. Romm's equation to estimate relative permeability curves in fractures. Later in 1994, D. A. Pieters and R. M. Graves (Pieters & Graves 1994) demonstrated experimentally that relative permeability curves are not a linear function of saturation. In this work, we use the concepts of shell momentum balance (Bird, Stewart & Lightfoot 2002), the equation of change for isothermal systems, Newton's law of viscosity and Darcy's law in order to derive an analytical equation to calculate relative permeability curves in fractured systems for two phase flow. These proposed equations assume gravitational segregation between the two phases (Rossen & Kumar 1992), Newtonian fluids, incompressible fluids, Laminar flow, steady-state and constant temperature.

These proposed equations in this paper could be applied to calculate relative permeability curves in two-phase flow systems in fractures. Further, the two-phase relative permeability curves can be used to predict the behavior of naturally fractured reservoirs. This work also includes a comparison of the calculated data between E. S. Romm's equation, Pieters and Graves's Laboratory data and the equations proposed in this paper.

As a result of this research we demonstrated analytically that relative permeability curves in two-phase flow in fractures are not a linear function of saturation. Also we confirmed the non linearity of the fracture's relative permeability curves using a reservoir and fluid data with the proposed equation.
Monitoring and Optimizing Oil Fields by a Real-Time Production Operation (RTPO) System
Authors: Dutra Thiago , Machado Leonardo , Rodriguez Miguel , Almeida Inaê , Montanha Breno , Manzali Marcelo , Dinis Marcelo , Carbone Leonardo , Fabricio de Souza Marcos , Herdeiro Marco
Published: December 2010

Companies worldwide have been investing in solutions to provide production and cost optimization. As a result, real-time operation systems have been used to help in achieving these objectives. This paper provides a description of the use of real-time operation systems and how the integration of their disciplines made it possible to optimize production and costs for oil and gas fields.

Working as an integrated multi-disciplinary approach, real-time production-operation systems enable the maximization of oil and gas production of assets at lower costs, while providing a better understanding of the current scenario of oil and gas fields. To obtain these improvements, some characteristics to be considered are described below. The consolidation of the whole asset- production data into a single system provides mechanisms to monitor, analyze, and control oil and gas fields. These data are automatically uploaded to the system to minimize manual efforts, making more time available for process analyses. To avoid spurious data, an automatic validation mechanism for the data acquisition process was developed. In addition to production monitoring and the enhanced data quality, historical data, alarms, and statistic tools are used to improve the data analysis and interpretation process. The solution also enables the online well-production prediction using a neural-networks model as well as the integration with a reliable system to identify, quantify, and classify production losses. Because the information is displayed in an online system, the same data at the same time are available for access from different users.

The use of real-time production-operation systems enables strategies for asset managers to make faster decisions and provide better solutions to asset operational issues.

These outcomes are achieved as a result of integrated production, losses, and process-parameters information, as well as the acquisition process of validated data and the availability of tools for analysis and interpretation.
Study for Improving the In-Situ Combustion of Venezuela Extra-Heavy Crude Oil Using Unconventional Additive
Authors: Mendoza R. A. J. , Perozo H. , Oliveros D. , Reyes N.
Published: December 2010

Venezuela has considerable heavy oil reserves; in consequence the evaluation of the potential technologies to be applied for its exploitation is required. Heavy and extra heavy crude oil reservoirs are produced initially using its primary energy. However, depending on the viscosity the production in other reservoirs will be directly by enhanced thermal processes. One of the thermal technologies that have been studied for more than three decades worldwide is the in situ combustion process. In the last ten years the use of additives has been important to promote the upgrading of the produced oil. Combustion process with additives has shown some advantages with respect to conventional combustion: (1) oil production increases, (2) faster combustion front, and (3) higher temperatures during the combustion. The main goal in the present work is to evaluate an additive for in situ combustion process in order to enhance it. Inexpensive waste stream was used as additive for upgrading the produced crude oil. The experimental methodology used is based first; in to introduce the additive in 2/3 of the total of the porous media, then the void space into the cell is completed with porous media without additive. After, the system is preheating, following by air injection applied into the porous media during the entire combustion test. Once the combustion front will face the additive, it acquires faster velocities and the front stability was reached quicker than during conventional combustion test. The results obtained with the additive shows the production of lighter compounds. It is a promising opportunity to exploit and to produce the Venezuelan heavy crude oil reserves. In consequence, it will be possible to get oil with more value in the market.
Integrated Optimization System for Short-term Production Operations Analysis
Authors: Rebeschini Jordani , García Alejandro , Lima André , Purwar Suryansh , Carbone Leonardo , Dinis Marcelo , Herdeiro Marco Antonio
Published: December 2010

Field-performance maximization is subject to an optimum tuning of the operations downstream in the reservoir. This single task is based on field-parameters surveillance, such as reservoir pressure, tubing and pipeline conditions, the equipment's capacity and availability. The quicker the engineer reacts to a change on these parameters, the quicker a production would be optimized or a loss minimized. This work addresses this problem by providing a real-time production-operations monitoring system implemented for an offshore field in Brazil.

The system is based on a workflow that integrates the most recent well models updated via well tests, current platform conditions, and gathering network models, and is designed to provide the optimal operational settings, including: a) production-processing train alignment, b) artificial gas-lift distribution among wells, c) choke opening, and d) compressor operating pressures. This workflow is accomplished by the user via an interactive web interface, where information is accessed, updated, and validated in real time.

The results are reflected in added barrels as result of a constant field-production improvement and improvement in data management tasks, such as data capture, information QA/QC, and models updates, with significant reductions in time.

The solution has proved to be a useful tool for the users in adjusting the operational settings on a daily basis or as needed in the presence of unexpected events, constantly optimizing the field production with its most-updated information.

This work was designed by production engineers and can also be used by any asset member to simulate the impact of planned or non-planned scenarios that can potentially change the operational guidelines of the day or a single period. Institutionalization of knowledge is a characteristic of this system, which makes it easy to use and to understand.
Pressure-Transient Analysis for Naturally Fractured Reservoirs With Transition Period Before and After the Radial-Flow Regime
Authors: Escobar F. H. , Martinez J. A. , Cantillo J. H.
Published: December 2010

It is expected for naturally occurring formations that the transition period of flow from fissures to matrix takes place during the radial flow regime. However, depending upon the value of the interporosity flow parameter, this transition period can show up before or after the radial flow regime. First, in a heterogeneous formation which has been subjected to a hydraulic fracturing treatment the transition period can interrupt either the bilinear or linear flow regime. Once the fluid inside the hydraulic fracture has been depleted, the natural fracture network will provide the necessary flux to the hydraulic fracture. Second, in an elongated formation, for interporosity flow parameters approximated lower than 1×10-6, the transition period takes place during the formation linear flow period. It is desirable not only to appropriately identify these types of systems but also to complement the conventional analysis with the adequate expressions to characterize such formations for a more comprehensive reservoir/well management.

So far, the conventional methodology does not account for the equations for interpretation of pressure tests under the above two mentioned conditions. Currently, an interpretation study can only be achieved by non-linear regression analysis (simulation) which is obviously related to non-unique solutions especially when estimating reservoir limits and the naturally fractured parameters. Therefore, in this paper, we provide and verify the necessary mathematical expressions for interpretation of a vertical well test in both a hydraulically-fractured naturally fractured formation or an elongated closed heterogeneous reservoir. The equations presented in this paper could provide good initial guesses for the parameters to be used in a general nonlinear regression analysis procedure so that the non-uniqueness problem associated with nonlinear regression may be improved.
An In-House Experiment About PVT Impact on Multiphase Metering Accuracy
Authors: Feria C. Correa
Published: December 2010

As a new development for a gas-condensate reservoir is ongoing, metering and allocation philosophy and methodology need to be selected. Due to severe environmental regulations (minimize footprint) and complex logistics (no roads, seasonal fluvial transportation and 100% helicopter transport to well clusters), multiphase metering seems to be a very interesting option when compared, for example, with conventional 3-phase test separators (large and heavy equipment).

Multiphase flowmeters (MPFMs) suppliers have always claimed for the need of using good quality PVT data to assure acceptable metering performance but, rarely have they been able to provide the operators with quantifiable data about this dependency:

What's the % effect of a % change in the input fluid composition (i.e. due to improper sampling, recombination or analysis)? How often do we need to obtain new PVT information? Why "six months" seems to be an accepted standard? In the absence of new PVT data, can we estimate the probable metering error to account for it in the final product balance? What's the relative importance of PVT related errors compared with inherent meter uncertainties (P-T gauges, gamma ray scattering and decay…)? …

As the answers obtained from almost every MPFM where always -more or less- the same and most of these meters still remain as black boxes, we decided to perform some in-house exercises and carry on future planning based on our own estimates.

Major points of PVT influence on MPFM performance were identified and a basic flowmeter simulator was built, using a standard process simulator and common office applications. This simulator was used to sensitize the influence of produced fluids' PVT changes over time and different MPFM PVT updating schedules, trying to reflect the cumulative errors on production metering and allocation. Based on results, an optimum schedule for acquisition of PVT data can be implemented during the life of the asset.

Perceiving MPFMs as black boxes has, for sure, impaired the spreading of multiphase metering technology in the oil and gas field. Acquiring better knowledge of how it works and being able to somehow quantify the involved uncertainties, worldwide operators should feel more comfortable and confident about the use of this promising technology.
Overview: Slug-Flow Characterization for Heavy-Oil Fields
Authors: Márquez J. , Trujillo J.
Published: December 2010

This work presents a review and selection of the mathematical models and correlations that could predict slug flow characteristics more accurately in heavy oil fields. These characteristics are slug holdup, slug length, slug velocity, translational velocity or Taylor bubble velocity, drift velocity, slug frequency and instantaneous flow. They were selected from different publications related to slug flow development both worldwide and from our multiphase flow laboratory.

The selected models and correlations are considered to predict better slug flow characteristics in heavy oil fields and therefore are recommended to be used for the Faja (Orinoco Oil Belt) surface facilities development.
Analysis of the Orinoco Oil Belt Development Through a Dynamic Simulation Model
Authors: Diaz S. , Quintero E. , Hernandez H. , Jenkins O.
Published: December 2010

The Orinoco Oil Belt located in eastern Venezuela contains the largest accumulation of extra heavy crude ever assessed in the world. This paper explores the opportunities for growth in this important area by using an innovative dynamic simulation model, built by the corporate team of PDVSA. It integrates subsurface, surface, economic, environmental, social, and strategic sub-models.

The situation analysis of the oil production in the Orinoco Oil Belt (OOB) aims at different forecast scenarios associated with the shortage of the use of diluents during its planned life and how it can be overcome in the future. As a consequence, options include the incorporation of exploratory activities in neighboring areas to obtain more diluents, technological investment, reallocation of resources, and the use of upgraders. All of these factors are introduced in a dynamic model and are simulated with different driving forces, such as budgetary cut by levels, market forces, and changing oil prices. We conclude that the integrated option with the upgrading process offers the best alternative investment for future plans, in conjunction with identified financing strategies. The recent oil prices variations have a strong influence as an incentive to exploration and development plans in this model.

The first dynamic simulation model in the OOB represents a significant effort to quantify the influence of different variables and their interaction for analyzing and developing scenarios when important decisions have to be taken. The prediction of future behavioral patterns of this complex system has a world scale impact, since this area represents a particular option available for the future world oil supply while oil demand continues to increase every year.
Cementing, Perforating and Fracturing Using Coiled Tubing: Rigless Completion Technique Developed for a Marginal Field in Peru
Authors: Salazar V. , de la Rosa V. , Gomez J. , Quintana J.
Published: December 2010

The Talara field, onshore Peru, is one of the oldest oilfields in the world. It was discovered in late 19th century and up to 2010 more than 12,000 wells have been drilled. Currently, only some 3,000 wells are active; the remaining ones have been temporarily or permanently abandoned due to low production.

Recently, a new pay zone was found above the typical producing formation in this field. However, two factors complicate any plans to recomplete the old wells and produce from the new formation. In first place, in the typical well configuration, the production casing in these wells is not cemented to surface and the cement top is below the new zone. Secondly, because the new pay zone is in a low-permeability formation, it must be fractured to be commercially produced. A conventional rig-based workover to recomplete and fracture this upper payzone is too expensive to be economically viable.

This paper presents a new rig less completion technique involving plug and abandonment of the lower zones, followed by cementing, perforating and fracture stimulating the new zone using only coiled tubing for intervention. The technique has proven to be an economically viable way to bring back to life the first 18 wells completed.

Operational details, production results and lessons learned from this first campaign are presented. The analysis demonstrates that this new system can reduce completion time and costs in open-hole wells for both mature and new fields.
Beyond the Mud-Weight Window: A Geomechanical Approach to Evaluating and Achieving Drilling Goals
Authors: Vargas Juan G. , Mateus Jefferson , Serrano Mario
Published: December 2010

It is well known that monitoring cuttings allows drilling engineers to take remedial solutions to control wellbore instability while drilling. Unfortunately, just the cuttings volume interpretation can be easily misunderstood and borehole instability can become unmanageable. Besides, most of the projects are drilled in very complex areas. If too much time elapses after wellbore instability begins occurring and the decision to modify mud density is taken too late, the final situation can be stuck pipe, fishing operations and finally the always expensive side track operations.

This paper presents a real example of geomechanical integration with drilling operations, not only during planning, but during the drilling stage, in an area with huge geological and geomechanical uncertainties.

During the planning stage, geomechanical and wellbore stability models were defined based on data analysis and pore pressure, mechanical properties, and stress profile predictions. As a result of the planning, the mud weight window, mud properties and formulations were defined as well as BHAs and casing points. While drilling, borehole conditions were monitored to optimize a "planning-while-drilling" wellbore stability model according to the changing wellbore circumstances. This methodology can allow all the well construction objectives to be achieved.
Integrated Production Modeling: Advanced but, not Always Better
Authors: Feria C. Correa
Published: December 2010

During the initial stages of a new gas-condensate field development planning, studies are performed trying to cover all possible key project factors. Reservoir performance estimations and production forecasts are, by far, the most important aspects influencing any other development requirements and future commitments (number, location and type of wells, capacity/modularity of the production facilities, sales contracts, booked reserves…). Due to the, let’s say, apparent simplicity of the project (homogeneous reservoir model, few development wells, linear gathering pipeline and small compression plant) and the uncertainty of available data, a handcrafted approach was preferred by working all models as separate items but, applying proper contour conditions for each one.

On the other hand, applying defined management methodology, project’s QA/QC explicitly required the development of an integrated subsurface-surface model, no matter the performance of the handcrafted approximation. Integrated Production/Asset Modeling (IPM or IAM) is a powerful asset design, prediction and management tool when properly used but, as with many other emerging or in fashion technologies, care should be taken when dealing with the ‘aspirin’ (good for everything) complex.

To fulfill this requirement, a full asset simulation model was built integrating the complete production cycle: numerical reservoir simulation, steady-state nodal wells, surface gathering/transport network and compression/processing facilities. The process was intensive, troubleshooting and time consuming but, as suspected, obtained results didn’t significantly improve the knowledge already available with the handcrafted initial approximation.

Being able to assess the proper use for each technology should be a basic pillar of our industry. Inefficiently and indiscriminately applying available tools without a suitable engineering criterion, could yield wrong assessments of their actual value and, lead to improper use of valuable time and workforce. Integrated Production Modeling develops real value when dealing with large systems, where the type and number of variables to be controlled lies out of the human capacity; however, simple systems still can be handcraftly managed under proper engineering judgment, without large troubleshooting processes, consuming less time and demanding less workforce. The cobbler should stick to his last.
First MPD Automated System Application in Offshore Gulf of Mexico Well Confirms Method, Huge Benefits
Authors: Ramirez S. , Aguilar R. , Herrera R. , Vallejo V. , Perez E. , Giral L. , Castiblanco G. , Sanchez H.
Published: December 2010

Land and offshore drilling operations along the Tabasco coastline of the Gulf of Mexico notoriously present difficulties posed by the variations in pore pressure, depleted reservoirs, and, in the majority of cases, highly fractured carbonates--the last a cause of negative windows between pore pressure and fracture pressure and, thus, whole sections with complete circulation loss. It is not surprising that the drilling of these deposits takes much more time than planned. Nonproductive-time (NPT) events are particularly associated with lost circulation and/or gas influxes in high-pressure formations, well-control processes, stuck-pipe problems, deviated wells, and in some cases, wells being abandoned without the objectives having been met. To mitigate these problems, managed pressure drilling (MPD) technology, using an automated system, was implemented. The objective was to determine the limits of the operating window and to perform an equivalent circulating density (ECD) control to find a balance between the losses and gains, reducing the losses as much as possible and minimizing volume of influx from high-pressure gas intervals.

This paper describes the objectives, planning, technology used, problems encountered, and lessons learned during the first application of MPD technology using an automated system in an offshore well in the Gulf of Mexico, along the Tabasco coastline.
Fiber-Assisted Self-Diverting Acid Brings a New Perspective to Hot, Deep Carbonate Reservoir Stimulation in Mexico
Authors: Martin F. , Quevedo M. , Tellez F. , Garcia A. , Resendiz T. , Jimenez Bueno O. , Ramirez G.
Published: December 2010

Carbonate reservoirs in the southern region of Mexico are characterized as deep, hot, and naturally fractured. Most wells in Cretaceous and Jurassic carbonate formations are acid stimulated at the time of completion and periodically during the life of the well to combat damage mechanisms that occur during drilling and production.

These wells are typically completed with multiple perforated intervals. Not all the intervals have the same density of natural fractures, some sections having no natural fractures. This creates a very high permeability contrast estimated to be as high as 1000:1 in extreme cases. Also, the reservoir pressure varies between the different intervals as a result of simultaneous production from zones with widely varying permeability. The contrasting permeability and reservoir pressure constitute a major challenge at the time of stimulation treatments in terms of achieving uniform zonal coverage and fluid penetration in all treated zones.

The treatments are bullheaded, so effective diverting fluids are required to ensure the complete vertical coverage of the zones of interest. The diversion, however, must be temporary and nondamaging to the reservoir and the natural fracture network. To meet this challenge, a degradable acid-diversion system has recently been applied in matrix acidizing treatments in southern Mexico.

The diversion system combines the viscosity-based effect of self-diverting acid with particulate-based diversion provided by degradable fibrous material. The combination functions synergistically to provide superior zonal coverage of matrix treatments under extreme conditions. In acid fracturing applications, the new system reduces leakoff in fissures and natural fractures, which leads to a more efficient spending of the acid and therefore longer fractures. The degradable nature of the fibers and viscoelastic surfactant result in no post-treatment damage. Furthermore, the fibers produce a weak acid while dissolving in the presence of water at bottomhole temperature, continuing to stimulate the well as they degrade.

This paper presents three case studies in which superior results were obtained by using the new diverter when compared to results achieved in offset wells in the same reservoirs and under similar conditions conventionally stimulated. Production increases in excess of 100% have been achieved where conventional treatments have failed to increase production. Lower production decline and higher flowing pressure have also been observed. The latter is interpreted to be the result of the fluid diverting from highly fractured and depleted zones into undrained lower-permeability with fewer natural fractures.
Geomechanics Aspects of the Oriente Basin, Ecuador, South America
Authors: Torres Manuel Ernesto , Frydman Marcelo , Goddyn Xavier , Medina Raul , Baker Andy , Bravo Oscar
Published: December 2010

The Oriente Basin of Ecuador is one of the most productive of the South American Sub-Andean Basins and it contains a sedimentary fill between Paleozoic to Recent age. Major commercial interest is confined to the Cretaceous depositional cycle and all the significant production comes from fluvio- deltaic and marine sandstones of the Hollin and Napo Formations. To reach prospective targets, the oil companies have to drill tertiary continental and transitional sedimentary formations, i.e Chalcana, Orteguaza, Tiyuyacu, Tena. The challenges to overcome could be summarized in formations reactive to the drilling fluids, tertiary overpressure clay stones, volcanic inter bedding layers, hard conglomerate intervals, limestone rocks, sand production in the reservoirs, cretaceous overpressure shales and magma type intrusions. The objective of this paper is to illustrate the geomechanic behavior of the wells drilled in Oriente Basin at a regional scale based on the geological framework model of several fields that have been drilled or stimulated by using 1D or 3D mechanical earth models- MEM, (Plumb, R.A, 2000).

A compilation of data from drilling and sanding prediction analysis, open hole logs, rock mechanical data by integrating rock strength characterization at the laboratory, borehole images, and formation pressure measurements are analyzed to assist in well planning and field development and to understand the problems already encountered in the existing vertical, deviated and horizontal wells. A complete characterization of formation stresses is included using traditional techniques of estimation derived from microfracs, mini-fracs, leak-off tests, hydraulic fracture data, poroelastic strain calibration, or derived from advanced sonic stress estimation using the induced anisotropy in the presence of variation of the three shear modulus crossing dipole dispersions obtained from near-wellbore stress concentrations.
Evolution of Rotary Steerable BHA Designs in Mexico Offshore: Solution to Stop Multiple Drillstring Failures in High-Vibration Environment
Authors: Ramirez Silvestre , Aguilar Rafael , Gonzalez Luis Felipe , Lopez William , Bautista Omar , Noriega Ivan
Published: December 2010

Pemex, the local oil producer in Mexico, has identified young fields as potential alternatives to compensate for the production decline experienced in recent years. However, those with the largest reserves and the lightest oil offer the most difficult drilling conditions. Just such an example is a target field in the Marine Southwest region where production objectives have been compromised by significant delays in drilling operation. The complexity of the 17 ½-in borehole section, made so by high lateral and torsional bottomhole assembly (BHA) vibration, resulted in costly drilling incidents, such as, drillstring twist off, physical damages, and failures of downhole tools. These incidents resulted in fishing and side track operations that averaged 15 days of nonproductive time per 17 ½-in section per well.

This paper will explain how rotary steerable BHA designs developed out of a need to achieve drilling stability and ultimately resulted in an enhancement on average ROP. This discovery, termed Powered Rotary Steerable System (RSS), combines, within the same BHA, a mud motor power section with a push-the-bit RSS tool. This system decouples surface RPM from downhole RPM allowing for the low revolution rotation of the drill string, thus preventing vibration but not sacrificing the rotation and hydraulic power needed by the bit to generate good rate of penetration (ROP). The design was capable of drilling the 17 ½-in section of the field in one run and reduced drilling time from 36 days to 8 days; nonproductive time due to BHA vibration was completely eliminated in additional wells.
Novel Approach for Fracture Characterization in a Metamorphic Reservoir
Authors: Velez E. , Vasquez J. , Frydman M. , Janampa H. , Meza O.
Published: December 2010

A new workflow reliably characterizes natural fractures in the highly complex Sechura basin in Peru, where acoustic logs alone were unable to characterize fracture networks adequately. The new approach, which integrates the response of borehole images with a dipole sonic tool, directly impacts the decision criteria of producible intervals where the zones that produce are the zones with open fractures aligned with the maximum horizontal stress. A case study of two wells in the Sechura basin shows how the methodology gives a quantitative way to better understand the fracture networks and fracture dynamics in naturally fractured reservoirs, establishing a novel criterion for fast decisions based on colored flags and horizontal stress directions.
Casing-Drilling Technology CwD Mitigates Fluid Losses in Peruvian Jungle
Authors: Gallardo H. , Cassanelli J. P. , Barret S. , Romero P. , Mufarech A.
Published: December 2010

This paper summarizes the experience reached drilling six wells using Casing while Drilling (CwD) technology in surface sections deeply affected by partial and total fluid losses in the Cashiriari field (Block 88 in the Peruvian jungle): three wells using a 24-in. casing drilling shoe, two wells drilled with a 12 ¼-in. casing drilling shoe and one well drilled with a 22-in. casing drilling shoe.

Total or partial fluid losses in surface (shallow) sections turn conventional drilling into a non-cost-effective way to drill this section in the Peruvian jungle. Additionally, the HSE risk and associated logistic problems were mitigated through CwD technology. Historically, fluid losses were observed in offset wells from 40m TVD to 500m TVD (Cashiriari 3 well) or 750m TVD (Cashiriari 1 well). Between 3,000 and 16,000 barrels of fluids were lost per well and conventional remedial methods were used, such as LCM pumping, cement plug, and unplanned casing points.

CwD technology demonstrated to be a beneficial technical-economical solution to drill and cement surface casing string (20- in., 18 5/8-in., 9 5/8-in.) in the Cashiriari field. CwD is the process of drilling a specific section using casing or liner as the drillstring. In the Cashiriari field, a non-retrievable casing drill shoe with polycrystalline diamond compact (PDC) cutting structures was used to drill soft to medium formations in surface sections. This technology helped to 1) reduce non-productive time (NPT), 2) improve the mechanical seal in the borehole due to the plastering effect, 3) improve the hydraulics in terms of hole cleaning due to higher annular velocity (reduced annular space between the casing and borehole), 4) reduce trip times, and 5) improve the HSE index due to a low associated risk and less personnel and equipment required. In all cases the customer goals were successfully reached. Compared with conventionally drilled wells, an average of five operating days was saved in the best cases.

The results show that this technology has significant applicability when casing rotation system is available for vertical, PDC- drillable sections. The objective is to reduce non-productive and casing running times where total and partial fluid losses make conventional drilling practices difficult or expensive.
Microseismic Hydraulic Fracture Monitoring to Determine the Fracture Geometry in Coyotes Field, Chicontepec
Authors: Gutierrez Guillermo , Sanchez Adrian , Rios Austreberto , Argüello Leopoldo
Published: December 2010

Due to the petrophysical characteristics of Coyotes field, it's necessary to fracture the sandstone reservoir to increase permeability to achieve commercial oil production. There are different technologies based on indirect measurements at the surface or at reservoir level that provide information about the fracture geometry generated in the well while the fracture is created, but all those techniques provide only partial information about the fracture geometry because they are limited by the depth of investigation. For this reason, PEMEX's technical team looked for new technologies for obtaining more precise information about the geometry of the fractures. The company selected a technology that offered monitoring and interpretation of microseismic events generated while the fracture propagated in the reservoir. This study documents the hydraulic fracture monitoring (HFM) of a group of wells located in Coyotes field and discusses the creation of 3D maps of the fractures produced.
Brazilian Pre-Salt: The Challenges of Coring at a New Frontier
Authors: Peixoto F. T. , de Souza I. S.
Published: December 2010

The recent discovered pre-salt reservoirs in Brazil have been plenty of challenges to coring, as well as other upstream areas. Its coring campaign warmed up in the middle of 2009 and has experienced good and bad moments, but the results were in general quite positive. This paper describes the problems and lessons up till now learned during these coring operations. The reservoirs are Cretaceous carbonate formations overwhelmed by a thick layer of rock; hence they are very hard and abrasive. Furthermore, the presence of faults increases jamming occurrence, when the core sample is not able to enter the barrel anymore due to friction factors. The unusual peculiarities of this scenario require unusual techniques, a new train of thought and an expertise restarting from square one. The lessons up till now learned will guide the next coring jobs at this scenario.

This paper also presents the results of an analysis obtained at this scenario, comparing the performance between different kinds of equipments or techniques, and jamming occurrence. Finally, the paper describes the obstacles faced during a salt coring. There will probably be a big exploration movement at this scenario in the next years. Start a coring job aware of what we will face may save a substantial time and money.