bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Use of Integrated Decision Making To Embed Sustainable Development
Authors: Kuijper M. , Stephenson M. , Howard M. 
Published: December 2007

Abstract
The necessity of sustainable development presents some significant opportunities and challenges to companies in the petroleum sector. They need to consider the consequences of their activity on the economy, environment and society, as well as how these domains interact with each other. There follows a requirement to integrate these consequences and interactions into corporate actions. And, since actions are the consequences of decisions, decision-making can provide a vital foothold for developing sustainable development thinking within the corporation. This paper describes Integrated Decision Making (IDM), an approached developed by Shell Exploration & Production in Europe designed to enable decision makers to contribute to sustainable development when executing their core responsibilities. The paper describes the theoretical background to IDM, its history, practice and some lessons-learned. The IDM approach continues to be improved by the authors.
Well Location Selection from a Static Model and Multiple Realisations of a Geomodel Using Productivity-Potential Map Technique
Authors: Narayanasamy R. , Davies D. R. , Somerville J. M. 
Published: December 2007

AbstractOne of major field development decision is choosing the number of wells required to efficiently drain an oil or gas reservoir. It is an interactive process in which various development scenarios are chosen and their performance analysed. Formation geology and zone connectivity have a major impact on the choice of well location since they determine well productivity. The industry's current well placement selection process is time consuming and costly. It requires analysing numerous development options by performing a large number of flow simulations.This paper describes a technique to partially automate this well placement process. It has been found that a new map which ranks the reservoir zones based on their productivity potential can speed-up, and hence reduce the cost, of this decision making process. This map, termed the Productivity Potential Map (PPM), is based on fundamental petroleum engineering principles. It is generated from the numerical reservoir models developed from standard data measured during the exploration and appraisal process. It incorporates both static and dynamic properties (e.g. porosity and saturation respectively).A static and stochastic numerical reservoir model are coupled with the PPM and well locations that maximise production are identified. The technique was tested using flow simulation models of two UK reservoirs by generating PPM and identifying the drilling targets that could deliver the maximum, sustained production potential.The first example uses a static reservoir simulation model of a field that had been production history matched for 18 years. Compared to the development plan implemented many years ago, the PPM map reduced the number of development wells by 15% while increasing the cumulative oil production by 2.6% at 2.5 years since production started. The second example employs multiple realisations developed from exploration well data using PETREL™. Well locations were chosen from a PPM map derived from these multiple realisations. The chosen well locations clearly matched the reservoir geology. Well locations were also chosen from a STOIIP based map. The performance of the STOIIP and PPM based field development were compared - the PPM based well placement consistently performed best.PPM thus reduced the flow simulation effort required, improved the flow forecast and reduced the uncertainty in flow performance. This paper will show that the use of a PPM is a quick and cost-effective technique for analysis of the reservoir production performance and the generation of drilling targets. The technique may also aid reservoir management decisions e.g. water flood front location and selecting the preferred water flood front direction.
Analysis of Possible Applications of Dual ESPs—A Reservoir Engineering Perspective
Authors: Davies D. R. , Narayanasamy R. , Kristensen B. , Somerville J. M. 
Published: December 2007

Abstract
Field installation of a dual Electric Submersible Pump (dESP) completion has been reported. The purpose of the second pump was to increase the pumping capacity and to act as a back-up to improve the reliability of the pumping system. However, dESPs can potentially address a much wider range of reservoir management challenges. This paper will analyse the performance of a dESP in a range of reservoir scenarios. It will show how dESP performance can be modelled using commercially available, coupled, well performance and reservoir simulation tools.
Four dESP applications were analysed. Where possible, the robustness of the numerical modelling results will be compared with analytical predictions. dESPs gave improved oil production and recovery in reservoirs with strong aquifer support and became progressively more attractive in a layered reservoir scenario as the pressure difference between the production zones increased. However, while dESPs had no significant advantages in a long, horizontal well placed in a homogenuous resevoir, they can increase recovery in a tilted, layered resevoir. Preliminary results on a deep-sea well example where the combination of deep-set single ESP (sESP) and a second pump placed at the seabed are discussed.
This work provides a comparison of the drivers for the choice of a sESP and a dESP in the scenarios studied. It illustrates a modelling methodology and provides dESP selection guidelines, thus aiding the increased application of this technology.
Beyond The Big Crew Change, Dumbing Down Or Getting Smarter?
Authors: Heaney M. , Davidson J. 
Published: December 2007

Abstract
The introduction of innovation and increasingly complex "Smart" technologies coincides with reduced manning levels, and the "big crew change". Corporate drivers require that the industry operate safely without damaging the environment, uphold and enhance company reputations while developing and maintaining producing on a shorter time line, reduce manning and control costs, extend the life of ageing infrastructure, accelerate development with minimised Opex minimised maintenance requirements and maximised uptime. As they reduce the requirement for intervention employees must embrace change and be open to innovation
Several soft "people factors" such as openness to change, enthusiasm for the new and an environmentally aware mindset may assist in improving the effectiveness of the systems.
Several other challenges also need to be addressed – over reliance on "Black box Data" or decision support systems that mask inexperience, and a willingness to take risks that may not be tempered by understanding.
This paper explores the strength of such effects and indicates several areas for attention. It evaluates several methods used to quantify these factors and present a methodology to address the emergent issues.
Stated simply, we have to provide easy access to years of experience for those who are coming next. We have to put old heads on young shoulders.
Steady-State Coning Solutions With Multiple Wells and Reservoir Boundaries
Authors: Ansari R. Z. , Johns R. T. 
Published: December 2007

Abstract
The critical oil (or gas) rate to avoid coning of unwanted fluids into production wells is an important design parameter. Simulation methods are useful to predict critical rates in reservoirs with complex heterogeneities and boundaries, but they are manpower intensive and prone to errors when large grid blocks are used. Current analytical methods are quick and easy to use, but their assumptions are too restrictive. Thus, there is a need for improved analytical methods that can account for well patterns and more complex boundaries, and also serve as further benchmarks for simulation.
This paper makes analytical solutions more realistic by extending existing single-well analytical solutions to account for multiple wells and common no-flow and constant pressure boundary conditions. A potential function is derived to superimpose existing single well coning solutions for single-or simultaneous two-phase flow. Capillary pressure and relative permeability effects on coning are included. The only limiting assumptions are vertical equilibrium (VE) and steady-state flow.
Comparisons with simulation show good agreement in predicted critical oil rates when steady state and VE are approached. VE and steady-state are approximately achieved when aspect ratios are greater than about 10. Even when aspect ratios are less than 10, the predicted critical rates are useful in that they are always conservative. The proposed analytical solutions are quick and easy to use compared to reservoir simulation and can be used in the development of downhole water-sink technology (DWS).
Experimental Investigation of Drainage Capillary Pressure Computed From Digitized Tomographic Images
Authors: Olafuyi A. O. , Sheppard A. P. , Arns C. H. , Sok R. M. , Cinar Y. , Knackstedt M. A. , Pinczewski W. V. 
Published: December 2007

Abstract
This paper presents comparisons between drainage capillary pressure curves computed directly from 3D micro-tomographic images (micro-CT) and laboratory measurements conducted on the same core samples. It is now possible to calculate a wide range of petrophysical and transport properties directly from micro-CT images or from equivalent network models extracted from these images. Capillary pressure is sensitive to rock microstructure and the comparisons presented are the first direct validation of image based computations. The measured data include centrifuge and mercury injection drainage capillary pressure for fired Berea, Bentheimer and Obernkirchner sandstones and unfired Mount Gambier carbonate. The measurements cover a wide range of porosities and permeabilities. The measurements are made on core samples with different diameters (2.5 cm, 1.5 cm, 1 cm and 0.5 cm) to assess the effect of up-scaling on capillary pressure measurements. The smallest diameter samples were also used to obtain the 3D micro-CT images. Good agreement is obtained between the experimental measurements and direct computations on 3D micro-CT images.
Optimum Selection of Artificial-Lift System for Iranian Heavy-Oil Fields
Authors: Taheri A. , Hooshmandkoochi A. 
Published: December 2007

Abstract
Kuh-E-Mond as the first priority of heavy oil prospect in Iran is located in southwest of Iran and 80 km southeastern of Boushehr, one of the important Iranian ports in Persian Gulf coasts.
Well MD-6 was spudded on September 19, 1984 for confirmation of the heavy oil occurrence in Asmari-Jahrum formation and Bangestan group in Kuh-E-Mond structure. Black tarry oil with gravity of 13 API degree occurred in the samples through most of the Sarvak limestone. Because there were no development programs in this field, the well was secured and the rig was released on May 5, 1985. The field was put on the development program on early 1999. The well MD-6 was opened and the static oil level in the well was 400 m below surface.
Clearly, some sort of artificial lift was needed in order to flow the well and restore the production rate to the normal levels and to maximize the ultimate recovery.
The decision of which artificial lift method to use is very important to the long-term profitability of the field. An improper selection of artificial lift can reduce production and increase the operating cost substantially. Once a decision has been made on the type to install on a well, it can be rarely altered whether or not the method selected was and still is the optimal for the existing conditions.
This paper presents the screening criteria on the different artificial lift techniques and discusses why the choice were confined to PCP as the most suitable techniques to be applied in this well. The paper studies the technical consideration behind each method of artificial lift for this well (Beam Pump, ESP, PCP, Gas Lift and Hydraulic Lift) and the technical discussions for selecting PCP.
Continuous 4D Monitoring is Now Reality
Authors: Arts R. , Brouwer J. , Hofstee C. , Kooijman J. , Drijkoningen G. 
Published: December 2007

Abstract
With the implementation of smart fields where sensors play a major role for measurement and control of the production process, continuous monitoring becomes increasingly important. In wells it is common practice to constantly monitor parameters like flow, pressure, and temperature. For imaging techniques like (active) seismics so far monitoring has only been applied in a time lapse manner with a repetition interval generally in the order of a year, not in a continuous way. The Vallhall field probably comes closest to continuous monitoring with permanently installed ocean bottom cables (OBC) and repeated surveys in the order of months.
The main challenge with permanent seismic monitoring is not so much the technical feasibility, but more the data transfer and processing of the vast amounts of acquired data. TNO together with the TU-Delft, KNMI and ASTRON have started to implement a seismic monitoring network in the Netherlands using an ultra-fast digital optical fibre network linked to one of the most powerful computers in the world, the IBM BlueGene/L system. Data can be sent to this computer at speeds up to 20 Tera-bits/second. Currently passive seismic data is constantly acquired at Exloo, the first out of 50 test fields to be installed in the next year.
Besides seismics, the network and the ICT infrastructure make it possible to combine all sorts of observations from the natural environment, infrastructure and processes anywhere and any time. This paper will give an overview of the first results of the incoming data and a description of the ICT infrastructure and network. Furthermore a view will be given on future applications.
Right Time Decision of Artificial Lift Management for Fast Loop Control
Authors: Campos S. R. V. , Silva M. F. , Correa J. F. , Bolonhini E. H. , Filho D. F. 
Published: December 2007

Abstract
This paper describes the efforts of Petrobras to design control strategies for artificial lift optimization. The work relies on several challenges starting with a process variable identification for each artificial lift method up to the implementation of control algorithms on wellhead. The target achieved is an artificial lift closed loop management.
Onshore and offshore cases will be presented showing the different sensibilities and importance that the same variable can represent depending on the artificial lift method and the well type completion. It will also be discussed an option of high level language tool to translate the experience of petroleum engineers into field algorithms.
Petrobras elected three values as the main target for fast loop design:
– First, to develop tools to add operational flexibility and right time decision for the artificial lift methods. The objective is to assure the best economical production point for each well, even under flowrate change due to zone selectivity and secondary recovery management. Another focus is to enable real time analysis, fault diagnostic and permanent monitoring. Technologies behind these tools are based on heuristics and artificial intelligence. – Second, to develop a methodology that facilitates the translation of knowledge from a senior petroleum well analyst into field strategies. A photography of the oil industry professionals shows an advanced age profile. The expertise of those engineers applied in real time is one of the milestones to reach the profits that the Smart field development allows. – Third, field connectivity and data availability. The automation architecture is designed to be hardware and software independent. The objective is to assure data to reach the analyst with transparency of hardware and software implementation. Communication specifications represent the project data flow assurance. This communication directive is the key for integration between smart completion and artificial lift automation. The synchronized production data integrated with reservoir engineering analysis built Petrobras strategy for fast and slow loop management.
Production Optimization with Adjoint Models Under Nonlinear Control-State Path Inequality Constraints
Authors: Sarma P. , Chen W. H. , Durlofsky L. J. , Aziz K. 
Published: December 2007

Abstract
The general petroleum production optimization problem falls under the category of optimal control problems with nonlinear control-state path inequality constraints (i.e. constraints that have to be satisfied at every time step), and it is acknowledged that such path constraints involving state variables are particularly difficult to handle. Currently, one category of methods implicitly incorporates the constraints into the forward and adjoint equations to tackle this issue. However, these are either impractical for the production optimization problem, or require complicated modifications to forward model equations (simulator). Thus, the usual approach is to formulate the above problem as a constrained nonlinear programming problem (NLP) where the constraints are calculated explicitly after the dynamic system is solved. The most popular of this category of methods (for optimal control problems) has been the penalty function method and its variants, which are, however, extremely inefficient. All other constrained NLP algorithms require the gradient of each constraint, which is impractical for an optimal control problem with path constraints, as one adjoint has to be solved for each constraint at each time step at every iteration.
We propose an approximate feasible direction NLP algorithm based on the objective function gradient and a combined gradient of the active constraints. This approximate feasible direction is then converted into a true feasible direction by projecting it onto the active constraints by solving the constraints during the forward model evaluation itself. The approach has various advantages. Firstly, only two adjoint evaluations are required at each iteration. Secondly, all iterates obtained are always feasible, as feasibility is maintained by the forward model itself, implying that any iterate can be considered a useful solution. Thirdly, large step sizes are possible during the line search, which can lead to significant reductions in forward and adjoint model evaluations and large reductions in the objective function. Through two examples, we demonstrate that the algorithm provides a practical and efficient strategy for production optimization with nonlinear path constraints.
A Service-Oriented Data-Composition Architecture for Integrated Asset Management
Authors: Soma R. , Bakshi A. , Orangi A. , Prasanna V. K. , Da Sie W. 
Published: December 2007

Abstract
The goal of an Integrated Asset Management (IAM) framework for the oil and gas industry is twofold. From the end users’ perspective, it should offer a single, easy-to-use user interface for specifying and executing a variety of workflows from reservoir simulations to economic evaluation. The framework should not require the user to be an expert in any of the underlying software applications; in fact, the details of selecting, configuring, and invoking the underlying software modules should be hidden from the end user. From the software development perspective, the IAM framework should facilitate seamless interaction of diverse and independently developed applications that accomplish various sub-tasks in the overall workflow. For instance, it should be possible to pipe the output of a reservoir simulator running on one machine to a forecasting and optimization toolkit running on another and in turn piping its output to a third piece of software that can convert the information into a set of reports in a specified format.
Combining Adjoint Calculations and Quasi-Newton Methods for Automatic History Matching
Authors: Rodrigues J. R. P. , Wachter A. , Conn A. , Moraes R. J. de , Silva F. P. T. da 
Published: December 2007

Abstract
This work describes the combination of adjoint methods for derivative calculation with a trust-region Quasi-Newton optimization algorithm for solving history matching problems. The techniques employed allowed for the resolution of problems with a larger number of parameters, when compared to other approaches, based on derivative free optimization or the forward method for derivative calculation.
Applications to both synthetic and real cases will be shown. A substantial improvement of the match was obtained in all examples. Problems with more than 250 parameters were solved efficiently. The ability to handle problems with a large number of parameters is exploited to discuss the possibility of accessing the uncertainty in the history matching process through exausting the space of possible models.
Injector-Well Completion Designs for Selectively Waterflooding Up to 18 Zones in a Multilayered Reservoir: Experiences in the Cerro Dragon Field
Authors: Massaglia E. , Baldassa D. , Ponce C. , Zalazar B. 
Published: December 2007

Abstract
The Cerro Dragon asset, located in the highly mature area of Golfo San Jorge Basin, Argentina, has around 30 producing structures; each one containing from 20 to 50 separate, highly heterogeneous, reservoir horizons, from 6 to 30 feet thick. From 1999 to 2005 proved reserves increased threefold and non proved reserves increased fourfold, moreover, oil production grew from 48,000 BOEPD to over 116,000 BOEPD, largely due to optimization and expansion of waterflood projects.
The aim of these projects was to increase the water injection rate from 248,000 BWPD to 714,000 BWPD along with the 1999 average of 5 reservoirs accessed per injector-well to an average of 12, with a maximum of 25, in 2005, keeping at the same time the highest possible control over the injected-water flow rate on each layer.
In an experimental process started in 2000, injector-well completions were designed and tested in several wells with different reservoir properties. The experience acquired with the analysis of these completions was used to improve them as well as to develop new ones. Today, this process continues, testing and enhancing new designs to fulfill the needs of the upcoming waterflooding projects.
This paper shows the experience acquired from 401 injector-well completions over the past 6 years, discuss the successes and problems encountered with each completion design under different reservoir conditions (i.e. differential pressures between layers). In addition, it contains information about the procedures and technology used to reduce the completion set up cost and to extend its useful life by solving leakage problems without replacing the completion installation.
The mayor achievement at this point of the process have been successfully running an injector-well completion of a total of 19 packers and 18 injector mandrels (with an average of 12 packers and 12 mandrels out of 48 completions ran on the first half of 2005).
The objective of this paper is to serve as a reference guide for injector-well completion designs in multilayered fields where a vertical expansion of the waterflooding projects is intended.