bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrating Production Operations and Economics Under Uncertain Conditions
Authors: Saputelli L. , Mijares G. , Rodriguez J. A. , Deaton D. , Sankaran S. 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

AbstractA 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.