bluuebunny/crossref_metadata_2025_split huggingface dataset:
Benchmarking Measurement and Automation Practices in the Upstream Business
Authors: Liddell B. , Deaton D. F. , Mijares G. 
Published: December 2007

Abstract
Whether we call it "digital energy", "digital oilfield of the future", "real time operations", "intelligent fields", "fields of the future" or "E-fields", there is a clear incentive to use technology to maximize asset operational value through increased production and improved efficiencies. The application of visualization, modeling, optimization, and control technologies is a critical component of this effort. This paper describes a study to determine current industry practices and establish a benchmark in the production measurement and automation (PM&A) area. Using a proven analytic methodology, specifically designed to survey and analyze technology utilization, 125 questions were grouped into 17 categories addressing people, process, and technology aspects of PM&A. The presented results are from ten leading independent oil and gas producing organizations.
Interviews were conducted to clarify the participants’ responses; and each response was reviewed and scored using pre-established criteria, consulting experience, and previous assessment results. Participants’ scores were compared to industry averages and the scores of the PM&A leaders using bar and radar charts. Questions included qualitative topics, such as the participants’ automation team organizational model, as well as quantitative questions like the number of engineers per well, and number of historian database points.
This comparison of practices between peer group members participating in the benchmarking process uncovered many significant areas of opportunity for the participants. The results in some categories were as expected and surprising in others. In general, there is a low level of utilization of PM&A, combined with a keen interest in doing more than is currently being done. A few companies exhibited high utilization of automation, with successful results, by leveraging organizations that promote strategic adoption of technology.
This study provides guidance to oil and gas producing companies desiring to increase their productivity through PM&A projects or those desiring to increase their return on PM&A projects. The benchmarking methodology described in this paper is part of a process that uses the results of participants’ current application of technology along with an assessment of the value of opportunities to determine the best path to take toward technology implementation, including strategies and project roadmaps. Studies by independent organizations such as CERA (Cambridge Energy Research Associates) point out quantifiable benefits from the application of digital technology in terms of percent of reserves recovery increase, percent of production increase, and percent reduction in operating costs (1). The presented effort focused specifically on improvements enabled by better measurement, modeling and control technologies. This study also focuses on how the successful implementers of technology are managing the implementation and postimplementation process to assure the capture of the expected benefits.
A New Method for Estimating Average Reservoir Pressure: The Muskat Plot Revisited
Authors: Crump J. G. , Hite R. H. 
Published: December 2007

Abstract
This paper describes a new method for estimating average reservoir pressure from long pressure buildup data based on the classical Muskat plot. Current methods for estimating average reservoir pressure require a priori information about the reservoir and assume homogeneous reservoir properties, or employ empirical extrapolation techniques.
The new method applies to heterogeneous reservoirs and requires no information about reservoir or fluid properties. The idea of the method is to estimate from the pressure derivative the first few eigenvalues of the pressure transient decay modes. These values are characteristic of the reservoir and fluid properties, but not of the pressure history or well location in the reservoir. The smallest eigenvalue is used to extrapolate the long time behavior of the transient to estimate the final reservoir pressure. The second eigenvalue can be used to estimate the quality of the estimate.
Numerical tests of the method show that it estimates average reservoir pressure accurately, even when the reservoir is heterogeneous or when partial flow barriers are present. Examples with real data show that the behavior predicted by the theory is actually observed.
We expect the method to have value in reservoir limits testing, in making consistent estimates of average reservoir pressure from permanent down-hole gauges, and in characterizing complex reservoirs.
Decreasing Well Downtime in Guando Oil Field by Using Continuous Sucker Rod
Authors: Ariza H. , Rojas C. , Rivera V. , Torres F. 
Published: December 2007

Abstract
The Guando oil field, located in Tolima, Colombia, and operated by Petrobras Colombia Ltd., has been developed with S-shape deviated wells, completed with progressing cavity pump (PCP) systems that are driven by centralized conventional sucker rod string.
The increase in sucker rod failures that has accompanied field development has lead to considerable well downtime—a major problem for field growth.
Sucker rod failures are associated with wellbore configuration and production conditions. To resolve the problem, continuous rod string has been implemented in some wells with outstanding success.
This paper describes the influence of wellbore configuration in the performance of conventional sucker rod, comparing the operation of wells with conventional sucker rod with that of wells with continuous sucker rod. Evaluation is based on downtime reduction.
The conclusion is that continuous-rod-string implementation has reduced production loss caused by centralized sucker rod failures in Guando's deviated wells.
Effect of Wettability on High-Velocity Coefficient in Two-Phase Gas/Liquid Flow
Authors: Noh M. , Firoozabadi A. 
Published: December 2007

Abstract
Gas well productivity is affected by two distinct mechanisms: (1) liquid blocking, and (2) high velocity flow in two-phase. The former has been studied extensively recently but the understanding of the latter is limited. High velocity gas flow in single phase has been thoroughly studied by a large number of authors. Despite the fact that high-velocity coefficient in the presence of an immobile and a mobile liquid phase is much higher than that in single phase, only a handful of studies have been carried on the subject. In this work, we have measured the high-velocity coefficient, β in two-phase gas-liquid flow. The results are presented as a function of liquid relative permeability and also liquid saturation. In our measurements, the wetting state is varied by the treatment with a fluorochemical compound. Then the effect of wettability on the high-velocity coefficient in two-phase flow is investigated. Results show that when the liquid is strongly wetting, the high-velocity coefficient increases some 270-fold in water-gas two-phase flow. However, our data show a systematic reduction of high-velocity coefficients for the altered wetting state in two-phase flow. We present measurements of the velocity coefficients in single-phase flow, and in two-phase flow for both oil-gas and water-gas flow for strong liquidwetting and altered-wetting states. Based on our measurements, we conclude that the treatment of the wellbore region can result in significant improvement in well deliverability from the large reduction of high-velocity coefficients.
Effective and Total Porosities: Their Reconciliation in Carbonate and Shaly-Sand Systems
Authors: Mezzatesta A. , Méndez F. , Rodríguez E. 
Published: December 2007

Abstract
Reconciling formation porosity and fluid distribution estimations in carbonate and shaly-sand systems represents a problem that log analysts and petrophysicists face in dealing with well log interpretation. The problem becomes especially challenging when data from conventional (e.g., density, neutron, gamma ray) and non-conventional (e.g., Nuclear Magnetic Resonance (NMR), multi-component induction) instruments are available and need to be combined in a consistent interpretation. Also, the use of effective and/or total porosity petrophysical models may lead to confusion and improper use and interpretation of those quantities.
The paper proposes petrophysical interpretation models for use in the evaluation of carbonate and shaly-sand reservoirs. They allow for effectively and consistently combining the various measurements under the framework of either effective or total porosity. Simultaneous and sequential solutions of the petrophysical models are proposed leading to consistent data integration and reconciliation of porosity and fluid distribution across the various available log measurements.
The proposed interpretation method focuses on the integration of NMR with conventional log measurements in carbonate and shaly-sand environments. With sufficient log data, rocks having complex mineralogy can be interpreted in terms of mineral volumes, irreducible and moveable water saturation, and hydrocarbon saturation. In a shaly-sand environment, results are expressed in terms of sand, shale and fluid saturation distributions.
The paper describes the mathematical formulation of the petrophysical model as well as the applied numerical techniques. Optimal interpretation results are achieved using forward modeling and a constrained, quality-weighted error minimization technique. Field data examples are presented that show the ability of the interpretation models to reconcile porosity, fluid type, and fluid distribution in the pore space.
A Locally Conservative Finite Element Framework for the Simulation of Coupled Flow and Reservoir Geomechanics
Authors: Jha B. , Juanes R. 
Published: December 2007

Abstract
In this paper, we present a computational framework for the simulation of coupled flow and reservoir geomechanics. The physical model is restricted to Biot's theory of single-phase flow and linear poroelasticity,1 but is sufficiently general to be extended to multiphase flow problems and inelastic behavior. The distinctive technical aspects of our approach are:
The space and time discretization of the equations. The unknown variables are the pressure, the fluid velocity, and the rock displacements. We recognize that these variables are of very different nature, and need to be discretized differently. We propose a mixed finite element space discretization, which is stable, convergent, locally mass conservative, and employs a single computational grid. To ensure stability and robustness, we perform an implicit time integration of the fluid flow equations. The strategies for the solution of the coupled system. We compare different solution strategies, including the fully coupled approach, the usual (conditionally stable) iteratively coupled approach, and a less common unconditionally stable sequential scheme.
This computational model has been implemented in an object-oriented reservoir simulator, whose modular design allows for further extensions and enhancements. We show several representative numerical simulations that illustrate the effectiveness of the approach.
Maximizing the Fidelity of Log Signals Transmitted via Digital Telemetry
Authors: Memarzadeh M. , Johnson D. , Gardner W. , Gao L. 
Published: December 2007

Abstract
The efficient and successful recovery of hydrocarbon resources depends heavily on the fast and high fidelity transmission of log (telemetry) signals to the surface. Regardless of the type of telemetry, wireline or wireless, the ultimate quality criterion for communication of log signals is the accuracy to which these signals can be reconstructed at the surface. An optimally designed system should be capable of transmitting as many log signals as possible, with each achieving a minimally acceptable fidelity level. In digital communication theory, the traditional metric for quantifying the transmission fidelity is the bit error rate (BER): the probability of bits being erroneously received at the receiver because of communication channel disturbances. Therefore, the commonly used criterion for designing digital communication systems is based on minimizing the average BER. This approach optimizes the system performance if all bits are equally important and need to be protected equally against transmission errors. Unfortunately, this criterion does not mean that high fidelity signals result.
This paper first presents the mean-squared error (MSE) distortion as a fidelity measure for the end-to-end performance of a digital telemetry system. We then introduce a specific transmission scheme—orthogonal frequency division multiplexing (OFDM)—that enables a simple implementation of a design criterion based on maximizing the end-to-end fidelity. We use the logging-while-drilling (LWD) acoustic telemetry scenario as a case study to demonstrate that, in contrast to optimizing BER, our design not only improves the quality of log signals but also results in significant gains in system throughput. Consequently, many more real-time log signals can be transmitted with acceptable fidelity than other techniques.
Online Water-Injection Optimization and Prevention of Reservoir Damage
Authors: Bringedal B. Ø. , Morud S. A. , Hall N. A. , Huseman G. 
Published: December 2007

Abstract
Waterflood injection on the Shell Bonga field offshore Nigeria is accomplished via a network of subsea flowlines and 15 subsea injection wells. Maximizing water injection volume is an important economic objective for Bonga. Water injection is used for maintaining the reservoir pressure and thereby maximize oil production. The water injection flowrate to each well is limited by the fracture pressure of the overlying shale layer. Fracture of overlying shale could significantly reduce oil recovery from the damaged reservoir.
Hence, it is important to accurately control the reservoir injection pressure such that volume of injected water is maximized without excessive risk of damaging the overlying shales. Since there are no downhole pressure gauges in the injection wells, the downhole injection pressure must be estimated from other measured variables.
For this, we developed a novel technology, WRIPS (Waterflood Reservoir Injection Pressure System). The WRIPS algorithm is used to: ■Estimate downhole injection pressure based on the model and available measurements■Estimate injection pressure uncertainty as a function of available measurements■Calculate an injection pressure target as a function of system conditions■Calculate injection rates for wells where the venturi has failed■Data reconciliation: calculate the most probable pressures and flowrates based on model, measurements, and sensor accuracies■Set conditioned alarm flags
The paper gives a brief description and the experience gained with WRIPS applied to water injection wells. The main contribution from the paper is to demonstrate the benefits with such a system and that the WRIPS is an attractive solution compared to expensive downhole pressure gauges.
Monitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and Carbon Credits
Authors: Benson S. M. 
Published: December 2007

Abstract
Large scale implementation of CO2 Capture and Storage is under serious consideration by governments and industry around the world. The pressing need to find solutions to the CO2 problem has spurred significant research and development in both CO2 capture and storage technologies. Early technical success with the three existing CO2 storage projects and over 30 years experience with CO2-EOR have provided confidence that long term storage is possible in appropriately selected geological storage reservoirs. Monitoring is one of the key enabling technologies for CO2 storage. It is expected to serve a number of purposes – from providing information about safety and environmental concerns, to inventory verification for national accounting of greenhouse gas emissions and carbon credit trading. This paper addresses a number of issues related specifically to monitoring for the purpose of inventory accounting and trading carbon credits. First, what information would be needed for the purpose of inventory verification and carbon trading credits? With what precision and detection levels should this information be provided? Second, what monitoring methods and approaches are available? Third, do the instruments and monitoring approaches available today have sufficient resolution and detection levels to meet these needs? Theoretical calculations and field measurements of CO2 in both the subsurface and atmosphere are used to support the discussions presented here. Finally, outstanding issues and opportunities for improvement are identified.
Integrated Production System Modeling in SPDC, Nigeria
Authors: Vlaardingerbroek R. , Emelle C. 
Published: December 2007

Abstract
As part of the Shell in-house simulation platform, the Hydrocarbon Field Planning Tool (HFPT) provides capabilities for the rigorous integrated subsurface-surface production forecasting in the medium to long term. The flexible programming language and the sophisticated development planning and contracts module have made the tool the core of SPDC's detailed project planning as well as of SPDC's business planning.
Shell aspires to attain zero flaring by end 2008 and so gas commercialization and the subsequent need to plan the size and quality of the various associated and non-associated gas streams; SPDC can no longer simply maximise oil production from its reservoirs, without first performing integrated capacity planning checks. With Associated Gas (AG) being routed to NLNG, there exist a high value optimization opportunity of supply and demand between the SPDC's fields and wells, the capacity of the various oil and gas processing plants (e.g. flow stations, terminals, associated and nonassociated gas plants) and pipelines, and the requirements of SPDC's various gas customers. HFPT addresses problems that cannot be resolved by stand-alone reservoir or surface facilities models and as such brings significant business benefits.
In order to address the above, various models are used in SPDC. The Corporate model describes all 3000+ oil drainage points and is used for annual reserves reporting and for the yearly business planning cycle. The model directly connects to a database.Stranded Assets model describes multi-phase flow from flow-stations without AG facilities to central processing facilities.NLNG supply model granted SPDC a 20-year LNG contract.Western Domestic Gas model (integrated production system with multiple fields that feeds into the prestigious Western Africa Gas Pipeline from Lagos to Benin, Ghana and Togo).Eastern Domestic Gas model (integrated production system feeding into local consumers via various contracts).Forcados-Yokri model, SPDC's largest oil field, were gas lift optimization saved investment in a second lift gas compressor.
A Physically Based Description of Dispersion in Porous Media
Authors: Bijeljic B. , Blunt M. J. 
Published: December 2007

Abstract
We establish a novel methodology to explain the complex macroscopic behavior of dispersion in porous media as a function of Peclet number, Pe, which is ratio of advective to diffusive time-scales at the pore scale. The work combines pore-scale network modeling, continuous time random walk theory and analysis of experiment. We provide a physically-based explanation for the macroscopic behavior of dispersion in porous media as a function of Pe using a pore-network model representing Berea sandstone that accurately predicts the experimental dependence of the longitudinal dispersion coefficient, DL, on Pe. We distinguish all the dispersion regimes, including the diffusive regime, the transition regime at low Pe, as well as the power-law dispersion and the mechanical dispersion regime at high Pe. We can predict the dependence of dispersion on time, Pe and pore structure.
Interpreting transport as a continuous time random walk, we show that: (1) the power-law dispersion regime is controlled by the variation in average velocity between throats (the distribution of local Pe), giving DL ~ Peδ with δ = 3-β ≈ 1.2, where β is an exponent characterizing the distribution of transit times between pores; (2) the cross-over to a linear regime DL ~ Pe for Pe &gt; Pecrit ≈ 400 is due to a transition from a diffusion-controlled late-time cut-off, to transport governed by advective movement; and (3) the transverse dispersion coefficient DT ~ Pe for all Pe &gt;&gt; 1.
We show that the asymptotic dispersion coefficient is only reached after the solute has traveled through a large number of pores, proportional to Pecrit at high Pe. This implies that pre-asymptotic dispersion is the norm, even in experiments in statistically homogeneous media. Furthermore, in natural systems at reservoir scales it is implausible to suggest that a truly asymptotic dispersion coefficient will ever be reached, since larger scales of heterogeneity that enhance dispersion are almost certain to be encountered.
A New Technique To Achieve History Match Using a Probabilistic Approach
Authors: den Boer L. , Poncet J. , Biver P. , Henriquel P. , Marlot V. 
Published: December 2007

Summary
The main objective of history matching is to improve reservoir representation in order to obtain reliable predictions of production rate and thus optimise future field developments.
Standard history matching techniques are composed of a fixed geological model with global modifications and local adjustments. The limitations with this methodology are clear: local adjustments are not always geologically realistic, static uncertainties are not taken into account and only a limited number of models are used for prediction. In order to solve this problem, a probabilistic approach is presented using uncertainty quantification throughout the history matching process.
This paper describes the process of geological and reservoir uncertainty quantification and ranking, and focuses on specific examples. The result of implementing such a workflow leads to reservoir models which honour the production history of the modelled field.
To achieve a history match, the workflow should consist of the following steps: Probabilistic multi-realizations of the reservoir model taking into account static uncertainty using JACTATM;Calculation of the impact of static uncertainties on the history match by means of reservoir simulation;Calculation of the impact of dynamic uncertainty on the history match using experimental designs;Evaluation of the relative importance of uncertain static and dynamic parameters;‘Hybrid’ geostatistical simulations;Calculation of the impact of the dynamic reservoir parameters on the history match using an experimental design technique;Adjustment of dynamic parameters to obtain a final history match.
This workflow provides the industry with the long-awaited possibility of addressing subsurface uncertainties in a systematic and objective manner. The history matching process shifts from deterministic to probabilistic and results in a more realistic reservoir model which can further be used for true risk assessment prediction.
The workflow proposed increases the chance of attaint the history match. Combining the structural, geological and dynamic uncertainties, covers the whole uncertainty domain, resulting in a multiple history matched reservoir models, which could be used for forecast calculation with more confidence.