bluuebunny/crossref_metadata_2025_split huggingface dataset:
Talking to the Reservoir through PDGs: A Brazilian Deepwater Oilfield Case
Authors: Feitosa Gilvan Soares , Lucas Marcos Aurélio 
Published: April 2012

Abstract
Production and injection bottomhole well pressures, when continuously monitored by permanent downhole gauges (PDGs), are sources of real-time valuable information on the reservoir behavior. Indeed, well flow rates and associated pressures constitute the language we talk to the reservoir, which must be understood by reservoir engineers. Controlled by reservoir-well parameters - such as rock and fluid properties, geometry and well constraints -, pressures and flow rates, when properly analyzed, are essential to guide the actions to optimize reservoir exploitation.
This paper presents the analyses carried on flow rates and associated pressure measurements recorded by PDGs placed at a pair of wells, an oil producer and a gas injector well, designed to drain a light oil deepwater reservoir, off coast of Brazil, and applications of its results to simulation models and reservoir management. The pressures so monitored have enabled to obtain valuable reservoir parameters and their evolution, through analysis of drawdowns, buildups and interference between wells. Main parameters and information include: volume of oil in-place, reservoir average pressure, productivity and injectivity variation associated with the evolution of damage and fluid saturation, and degree of communication between wells. In particular, these data have improved the history matching process, thus contributing to shape up more reliable simulation models that have been used for production forecasting.
Pressure recordings span over one and half years and include a huge amount of data, over 11 million points, one of the challenges that had to be handled. It is shown that the deconvolution applied to the measured pressure-rate data stretches the period suitable for analysis, leading to deeper reservoir investigation, detecting boundaries that otherwise would be unnoticed, what makes PDGs pressure recordings even more valuable. Due to high transmissibility and size of the reservoir, the pressure responses to disturbances caused by heterogeneities and boundaries, as well as by variation in well flow rate, are readily sensed and registered by the PDGs in short period of time, at both the producer and the injector well, what yields recording real world textbook-like reservoir behaviors, which may not be often found in the literature.
Wireless Reservoir Surveillance Using Intelligent Tracers
Authors: Williams B. , Vilela A. 
Published: April 2012

Abstract
Today's field developments are increasingly being characterized by very complex wells in very demanding and costly operating environments. Not only are individual wells challenging, but most are part of a complex reservoir network that must be managed over an extended period.
The high cost and risks of acquiring surveillance information using conventional technology, such as production logging tools, is forcing operators to forgo acquisition of fluid inflow distribution information and manage these fields with a blurred understanding of the reservoir.
Intelligent chemical tracers are a new technology that consist of smart plastic and unique chemical compounds that are combined into a matrix that resembles strips of plastic. The matrix is designed to be sensitive to either oil or water. For example, when water sensitive matrix is contacted by water, the matrix releases its unique chemical fingerprint (tracer) at a prescribed rate. The water sensitive matrix is dormant when contacted by oil, gas or air. Oil sensitive matrix behaves in the same way.
Strips of matrix are easily adapted to any completion configuration including conventional sand screens, ICD sand screens, packers, pup joints, intelligent completions or artificial lift hardware. The matrix can be deployed in any well type including horizontal wells and multilateral wells.
Intelligent tracers are economical, easy to deploy and have none of the negative effects of radioactive isotope-based surveillance techniques. Long service life in combination with model-based interpretation techniques of tracer flowback concentrations are the main enablers that tell operators if the entire interval is flowing, where oil is entering the well and where water is entering the well.
Samples of produced fluid are analyzed for the concentration of each tracer. This data provides the operator with insight into the relative contribution of well segments and which well segment is the source of water breakthrough.
This paper will review how the technology works, recent case histories of intelligent tracer responses and the insight the operator gained from deploying the technology.
Surge and Swab Pressures in Horizontal and Inclined Wells
Authors: Srivastav R. , Enfis M. , Crespo F. , Ahmed R. , Saasen A. , Laget M. 
Published: April 2012

Abstract
Surge and swab pressures generated during well construction operations are critical. As thousands of wells are drilled every year, challenges associated with downhole pressure management have become more important for the oil industry. Inadequate estimation of surge and swab pressures can lead to a number of costly drilling problems such as lost circulation due to formation fracture, fluid influx resulting in kicks, breakdown of the formation at shoe due to limited kick tolerance or blowouts. An accurate surge pressure model is very important in planning drilling operations, mainly in wells with narrow safe pressure window, slimholes, low-clearance casings, deepwater, and extended-reach well applications.
Existing surge/swab pressure models assume concentric wellbore. This assumption is hardly ever valid in horizontal and inclined wells with some degree of eccentricity. Ignoring the pressure reducing effect of eccentricity on surge and swab pressures may eventually lead to underestimating the tripping speeds, and thereby increase non-productive time and operation costs. Eccentricity between the wellbore and the drillpipe adds more complexity to surge and swab pressure calculations. Recent studies have indicated that surge pressure can be significantly reduced due to eccentricity. Although the numerical investigation shows encouraging results, understanding of pressure surges in wells with eccentric annular geometry is very limited.
This paper presents the results of experimental investigations conducted to study the effects of eccentricity on surge and swab pressures. Experiments were performed in a test setup, which consists of fully transparent polycarbonate tubing, and inner pipe that moves axially using a speed controlled hoisting system. During the experiments, test fluid viscosity, trip speed, and eccentricity were varied. Experimental results were compared with predictions of existing models showing a satisfactory agreement. Results confirm that trip speed, fluid rheological properties, annular clearance and eccentricity significantly affect the surge pressure. In some cases, eccentricity can reduce surge and swab pressure by around 40%. Applying regression analysis, a generalized correlation has been developed to account for the reduction in surge pressure due to the eccentricity of the drillpipe.
Automation Master Plan Framework: Case Study
Authors: Herrera D. , Avelino J. , Sánchez J. , Díaz O. , Galán A. , Bravo C. , Rodríguez J. , Torre M. 
Published: April 2012

Abstract
Given the complexity and diversity of the PEMEX enterprise processes and the geographical dispersion of its facilities, the industrial automation platform has become a key element of the company's technological architecture. The automation master plan (AMP) framework includes strategies, architecture guidelines, and technological trends required to reach the enterprise production goals, with safe and environmentally responsible processes and with maximum profitability. The AMP framework includes an analysis of the automation requirements for all PEMEX business units and the development of corporate industrial automation architecture, designed to accomplish this requirements.
The industrial automation architecture was developed based on service oriented architecture (SOA). This architecture covers the various levels related to production management, from the production control and supervision systems, to the business processes automation and the presentation of the process information. Integrated asset management concepts were used to define the architecture, which were extrapolated from upstream processes to other processes in the value chain, e.g., transport, refining, gas, and petrochemical.
This paper describes the different project phases of the automation master plan, the automation architecture, and the initial benefits realized from such implementation.
Improved Reservoir Characterization of Tight Gas Sands through the 3D Integrated Reservoir Modeling of Queen City Basal, Burgos Basin, Mexico
Authors: D'Alessio S. , Muñoz L. , Ochoa A. , Garza E. , Brito F. 
Published: April 2012

Abstract
A real case application is presented in the following study of the methodology for the characterization of the Eocene tight gas sands located in Burgos Basin, Mexico.
The depositional arquitecture, complex mineralogy, low permeability, and diagenesis, threaten the understanding and commercial development of Queen City reservoirs. The aim of this study is to integrate the geological model, the petrophysical model, the simultaneous inversion study, and the production history as part of the 3D reservoir model workflow. The methodology can be divided into three main steps: First, a high resolution correlation, log facies analysis, stacking patters, sedimentary environments, and the creations of the 3D structural grid. Then, the petrophysical model based on the Wiland concepts calibrated with the production performance, the rock physics analysis, the geobodies, and attributes generated cross-plotting P and S Impedanceis carried out and considered as part of the elastic inversion AVO/AVA. Finally, a 3D facies and property model is developed to integrate regional trends and variogram analysis in conjunction with geobodies and attribute trends coming from the simultaneous inversion which gives a reliable spatial distribution of facies and properties. By the use of Sequetial Indicator Simulation algorithm (SIS), several facies realizations are generated and relevant sets of petrophysical properties are modeled.
The developed workflow has been applied in a case study in the Eocene tight gas sands of the Queen City Basal reservoir. A new reservoir model was created, able to discriminate shale prone zones and zones affected by diagenesis. Two main productive flux units were characterized in conjunction with the production history of this sands related to individual completions.
The contribution of the presented study is to provide a methodology of characterization of tight gas sands reservoir with complex lithology in intermediate stages of development, given importance of well and seismic data for property modeling.
Reviewing Mature Fields - A Case History
Authors: Martino Luis , Iuliano Alberto , Ucan Sezai , Hern Caroline 
Published: April 2012

Abstract
In Argentina, over the last decade mature field management has been of paramount importance in ensuring economic sustainability for many oil field operators. Success requires solving a specific suite of problems comprising mixed generations of technology (in particular logging tools), long and complex well histories and often the sheer size of the dataset.
The field in this case study has been in production since 1964 reaching its maximum production capacity of 32000 bpd during 1969, after which decline began. Consequent depletion from 140kg/cm2 to 20kg/cm2 drove the need for pressure support that was achieved through waterflooding which was implemented in two major campaigns during the 70's and the 80's. A total of 354 wells comprise the historical dataset with recent re-drills, extensions and infills bringing the total well count to 422. Re-evaluation of the remaining target via a series of studies carried out between 2006 and 2009 indicated an attractive opportunity for 7 spot waterflooding and saw the commencement of a massive re-development of the field.
Behaviour of recent wells has been worse than predicted. This deviation from expectation initiated a series of studies to better characterize the reservoir with the objective of re-defining targets for incremental development. Associated with these studies new geological and dynamic models were built using re-evaluated historical data integrated with information from 68 new wells and 8 new cores. In particular, the impact of textural variation and thin bed architecture on the meso-scale oil distribution was assessed allied with a range of different techniques to identify macro-scale compartmentalization. The result was an integrated model that enabled comprehensive re-evaluation of the remaining targets.
The approach used in this study to identify and characterize thin beds in this type of setting, define the impact on OOIP and determine the remaining oil in place in order to evaluate opportunities can assist many operators who experience various challenges associated with developing mature acreage.
Parallel Preconditioners for Reservoir Simulation on GPU
Authors: Liu Hui , Yu Song , Chen Zhangxin , Hsieh Ben , Shao Lei 
Published: April 2012

Abstract
In this paper, we present our work on developing parallel preconditioners for iterative linear solvers on NVIDIA Tesla GPU. A unified triangular solver for ILU-like preconditioners is developed. A new matrix format and the corresponding parallel algorithm are designed. Based on this triangular solver, block ILU(0), block ILUT and domain decomposition preconditioners are implemented. Numerical experiments show that these GPU based parallel preconditioners are around 8 times faster than our CPU based preconditioners.
Simulating Progressive Cavity Pump for Multiphase Flow and Production System Design
Authors: Zhang He , Li Jun , Wang Wenhao , Watters Colin , Houeto Fabien 
Published: April 2012

Abstract
A progressive cavity pump (PCP) characterization model is developed to predict flow characteristics under varying multiphase flowing conditions.
This paper presents a procedure for modeling PCPs and its integration to grid-based network solvers including successively accelerated substitution (SAS) and Newton-based. Our numerical study shows the latter leads to a much lower computing cost than that of its counterparts. This PCP model also provides calibration capacity on the performance curve at in-situ PVT properties.
This modeling work will assist production engineers in PCP related jobs, including: PCP surveillance, well planning, nodal analysis, and network optimization.
Development of the Brazilian Pre-Salt Fields – When to Pay for Information and When to Pay for Flexibility
Authors: Moczydlower B. , Salomão M. C. , Branco C. C. , Romeu R. K. , Homem T. R. , Freitas L. C. , Lima H. A. 
Published: April 2012

Abstract
The Santos Basin Pre-Salt Cluster (SBPSC), Offshore Southeast Brazil, is a unique scenario, posing great development challenges. The microbial carbonate reservoir is unusual regarding its origin and petrophysical properties; the fluids have a variable CO2 content; the few analogue reservoirs around the world do not compare in terms of volumes, water depth and distance to the coast; and there are also flow assurance issues.
Considering the importance of these reserves for the Brazilian economy and the opportunity to accelerate cash flow, Petrobras and its partners have opted for a fast track development, including extended well tests (EWTs) and production pilots. The current Petrobras Business Plan (2011–15) foresees that the SBPSC areas alone will produce over 500,000 boe/d in 2015 and over 1,100,000 boe/d in 2020. These numbers refer only to Petrobras share and do not include the transfer of rights with economic compensation from the Brazilian government to Petrobras.
Therefore, the initial development phase will have to cope with several uncertainties, mainly the subsurface ones. Some of the most relevant are the quality and the heterogeneity degree of each reservoir zone; the compositional grading of the fluids; the performance of different EOR methods; and the presence of fractures affecting the flow. How to specify and anticipate the acquisition of expensive equipment, such as FPSOs and subsea devices, with uncertainties to be clarified? When is it worth to invest in more data acquisition, such as EWTs, core and fluid sampling, extensive lab analysis or even more appraisal wells? The timing and the uncertainty reduction foreseen for each initiative must be taken into account. On the other hand, when is it better to pay for extra flexibilities, accepting the inevitable CAPEX increase? Some examples would be: smart completions and possibility to inject different chemical products in the wells; gas and water separated lines for each satellite injector; flexible subsea layout, allowing multiples strategies and the addition of more wells; FPSO plants designed to inject desulphated water, or to export, import or reinject the gas, and also to separate variable CO2 contents in the produced fluids.
This paper aims to discuss the influence of the main subsurface uncertainties in the selection of alternatives to develop the giant fields in the SBPSC, in a fast track way.
South Sen Field Dynamic Analysis, Mexico South Region
Authors: Cabrejos M. B. , Guevara L. F. , Orozco G. Sanchez 
Published: April 2012

Abstract
Sen field was discovered in mid 1984 with full exploration beginning in May 1987. The exploration area consisted of 30 wells, 6 of them which remain active today; reservoirs are from dolomites, where fractured Middle and upper Cretaceous limestones currently provide the majority of 'production. The field produces 40° API volatile oil with extremely low matrix porosity (0–3% average) and natural fractures as the primary production source.
A need to evaluate the fluid diffusion inside the pore system arises from well depletions rates, sudden water breakthrough, so as to find production opportunities and non-drained areas. A dynamic analysis and its integration with a productivity analysis was proposed to help us understand the reservoir dynamics and the well productivity behavior.
Well tests interpretations and matching with production rate record, the so called dynamic analysis, is nowadays one of the main reservoir characterization methods and thus, can become a very important tool to set the right reservoir developing strategy.
This paper discusses the applied methodology, for this purpose well test and production analysis specialized software were used. The first step was to interpret the buildup and draw-down well tests under a Pressure Transient Analysis outline; then, these analyses and the production record were matched to achieve an improved reservoir's model definition. Once these analyses were over, equivalent time synchronization was done to the production and pressure performance of each well, having as a basis the reservoir's model that was built from the well test interpretations. As a result, a great data matching was established thereby obtaining the reservoir's parameters, oil in place, depletion rate and production forecast to rely on better reservoir's characterization and overview, thus increasing reservoir's productivity
Sand Exclusion or Management: Multidisciplinary Approach in Decision Making
Authors: Jaimes M. G. , Quintero Y. A. , Martin D. P. , Puentes M. S. 
Published: April 2012

Abstract
Sand production in many oil and gas fields is a critical problem that lowers their profitability. The impact can be reduced if the analysis is approached from a multidisciplinary focus that can guide the decision making.
Based on the above, this paper focuses on developing a practical methodology, which integrates information from field and laboratory to select and evaluate alternatives of sand exclusion or management, to facilitate making of the best decision from the technical and economic point of view.
The study includes: selection of wells and quantification of costs associated with interventions by sanding problems, root cause of the problem of sand production by predictive models, charts of diagnostic and characterization of intervals with sand production, selection of alternatives to sand exclusion or Management, production modeling, technical-economic assessment of selected alternatives, implementation and subsequent evaluation of the work performed.
To accelerate the decision making process, the methodology was automated by developing a software tool, which generates standards of the information required for its application, developing of optimal workflow that reduces evaluation times by well over 50%, and creates an environment graphical friendly for the user.
The study was conducted in the formations sensitive at sand production of the fields: Lisama, Llanito, Galan, Brisas and Yarigui-Cantagallo in Colombia, and in the wells where the alternative sand exclusion or Management recommendedwas implemented, it was possible to reduce the frequency of interventions in more than 50% and increase their productivity. This paper presents the application results in wells Lisama 166, and Galan 135.
Finally, the main findings, conclusions, recommendations and field results obtained in this study are shown.
Optimizing CO2 Injection in an Offshore Field Considering Operational Constraints
Authors: Rosa M. , Branco C. 
Published: April 2012

Abstract
The continued increase in oil demand associated with the growing concern about the greenhouse gases has been an additional driver for CO2 injection into oil reservoirs. The application of this EOR method usually occurs at a later stage in the development of a field in which the operating surface facilities were normally not specified to manage high levels of CO2. Therefore, the aim of this work is to evaluate, by proper fluid characterization and compositional reservoir simulation, the benefits and risks of CO2 injection in a particular sector of an offshore reservoir, surrounded by production units not fully specified to deal with elevated concentrations of CO2.
The presented workflow, combining reservoir engineering analysis with production equipment aspects, can be applied to any target field for a CO2 injection project. However, it is even more relevant for mature offshore fields, where a CO2 production growth leading to the necessity of replacing all production facilities would probably make the project fail economically.
For the particular field analyzed in this article, the deployment of a production unit able to inject CO2 from an external source in an undrained region of the reservoir, hydraulically connected to an area already in production, would bring benefits not only to the region where the injection would occur but also to the adjacent area. The CO2 migration to the neighboring area decreases the levels of CO2 to be processed in the new platform plant, allowing its technical and economic feasibility, as well as increases the recovery factor of the adjoining area, without reaching levels of CO2 and gas flow rates beyond the limits of the plant already in operation. Furthermore, the reservoir's capacity to retain CO2, acting as a carbon sink, is also evaluated.
This study thus presents an integrated workflow for an optimal CO2 injection project design, considering not only the benefits in terms of recovery in the target area of the project, but analyzing the impacts and risks to surrounding areas.