bluuebunny/crossref_metadata_2025_split huggingface dataset:
Peregrino: An Integrated Solution for Heavy Oil Production and Allocation
Authors: Beall R.. , Sheth K.. , Pessoa R.. , Olsen H.. 
Published: September 2011

Abstract

An Integrated Solution Enabling Allocation of Heavy Oil in the Peregrino Field
The complexity of producing from a heavy oil reservoir is a challenge limited by both economics and available technology. Various methods exist for producing from heavy oil reservoirs, but in areas such as Latin America, cold production is used where electrical submersible pumps (ESPs) are employed to artificially lift the oil from the reservoir.
This paper highlights an integrated approach of using ESPs and downhole flowmeters in heavy oil production. It will focus on the validation and analysis of production performance from ESPs and the allocation performance of the downhole flowmeters used in multiple wells in Peregrino field, offshore Brazil to address huge variations in the wells’ behavior such as production rates and bottomhole pressure.
A test was commissioned to benchmark ESP and flowmeter functions when working in tandem. Three sizes of ESPs and flowmeters were tested over the flow range of 500stb/d and 22,000stb/d and up to 360cP in oil viscosity. The ESPs were operated from 2300 to 3600 rpm in the different viscosity fluids and used water data as a baseline to calculate the performance correction factors for each operating condition. The performance correction factor is incorporated into the development of software to predict the performance of each pump at a specific operating condition. Eventually, the data will be used to develop the ESPs’ monitoring tool.
In the downhole flowmeter test, new correction methods were employed to improve the measurement accuracies such as an iterative calculation of the discharge coefficient based on the measured fluid properties. Test results will help validate ESP performance and verify flowmeter allocation accuracies to meet ANP specifications. The lessons learned will be applied toward future field allocation application using downhole flowmeters in the Peregrino field.
Investigation on Variations in Wettability of Reservoir Rock Induced by CO2- Brine-rock Interactions
Authors: Zhu Zihan , Li Mingyuan , Lin Meiqin , Peng Bo , Sun Liang , Chen Long 
Published: September 2011

Abstract
Originally, the reservoir rock surface is hydrophilic at atmosphere pressure, because they are generally consisted of hydrophilic minerals, such as quartz, feldspar, calcite, dolomite and clay minerals. According to different hydrophilic magnitudes of different minerals and Cassie's law, the heterogeneous reservoir rock surface shows different hydrophilic magnitudes with different mineral compositions. Therefore, after CO2-brine-rock interactions, minerals dissolution and precipitation will change the mineral composition and the hydrophilic magnitude of the reservoir rock surface at the same time.
The present study implemented a CO2-brine-rock system in laboratory with elevated CO2 partial pressures at 323K and 343K. Surface properties of the reservoir rock (such as wettability, surface mineral composition, surface topography and surface element composition) were respectively determined by Wilhelmy plate, XRD, SEM and EDS method before and after CO2-brine-rock interactions. The contact angle results show with the increasing CO2 partial pressure, the contact angle of water on the reservoir rock surface increases at 323K, and decreases at 343K. SEM results show minerals dissolution and precipitation were both taken placed on the reservoir rock surface after CO2-brine-rock interactions. EDS results indicate carbonate minerals dissolution plays a dominate role at 343K, and secondary carbonate minerals precipitation mainly occur at 323K. There is a close relation between the contact angle variation of water and the element mole percentage variation on the reservoir rock surface. With the increasing O, Si, Al, Na or K mole percentage, the decreasing C or Fe mole percentage, the rock surface becomes more hydrophilic.
Safe and Energy-Efficient Method for the Initiation of an In-Situ Combustion
Authors: Grachev N. E. , Senin D. S. 
Published: September 2011

Abstract
Initiation of the in-situ combustion (ISC) may be accompanied by rapid increase of oxygen concentration in the production fluid. This may cause serious damage to the well equipment by corrosion or explosion.
The most common method for reducing the risk of incomplete oxygen consumption (and oxygen breakthroughs) is pre-heating of the bottomhole zone with the use of well steam treatment (WST) technology. It is possible to optimize the initiation of ISC process - to minimize amount of injected steam, to achieve maximum air injection rate in a fastest way and to ensure that no oxygen breakthroughs to producing wells will occur during initiation of the ISC process.
We propose a method for initiation of ISC based on the developed semi-analytical model. Our approach allows to calculate the increasing air injection rates, from initial value to maximum acceptable value. The method is applied to model prevention of oxygen breakthroughs and to provide fast and safe initiation of an the ISC. Two cases are considered: initiation of ISC in the reservoir with the initial constant temperature and initiation of ISC in the reservoir with the pre-heated zone around injector well. In addition, we develop a method of optimal initiation of ISC after WST that allows to spend a minimum amount of energy and to satisfy the conditions of effective, fast and safe initiation of ISC.
The CMG STARS reservoir simulator was used for testing the developed model. The results which were obtained in accordance with the developed semi-analytical model are in full agreement with numerical experiment.
Kadanwari Field: A Tight Gas Reservoir Study and a Successful Pilot Well Give New Life to an Exploited Field
Authors: Valzania S. , Kfoury M. , Grandis M. , Valdisturlo A. , Fanello G. , Guerra L. , Heikal S. , Kashif A. , Sultan A. 
Published: September 2011

Abstract
Kadanwari field in Middle Indus Basin (Pakistan) was discovered in 1989 and brought on stream in 1995. The producing reservoirs are Cretaceous Lower Goru sands D-E-F-G. The gas production started from better quality E and F sands; after 2004 layer G started to drain western block of the field, with the first hydraulic fracture job made in Pakistan (well A). Layer G represents a complex target for petrophysical characterization; reservoir sandstones are micro-porosity rich, with variable presence of Chlorite affecting flow properties. Positive results encouraged the operator to drill & frac well B and to consider possibility to extend gas production throughout western block, including sand reservoirs of variable quality, from moderate to tight.
The paper describes how reservoir study faced layer G complexity and how production data of wells A and B allowed a post frac-job evaluation integrating well-test data and frac-job interpretations into 3D dynamic model. After history match, the computed GOIP suggested an infilling program in G sand reservoir, with side-tracks of existing wells and new wells, all hydraulically fractured. So far, one sidetrack and one new well have been drilled; results fully confirmed the complexity of local geological setting. The sidetrack revealed rock quality slightly better than expected (frac not necessary). Pilot well C targeted G-Sand in a sweet seismic anomaly in western area, a gas flare was observed during DST pre-frac. Mini-Fall Off was conducted to estimate closure pressure and effective mobility, but permeability computed from MFO was not conclusive due to important filtrate invasion. DST post hydraulic fracture job confirmed commercial gas rate production higher than 1 MMscfd with a peak of 3.5 MMscfd. The successful pilot well results open new horizon to improve reserve from tight sand of Lower Goru formation.
A Case Study of the History Matching of a Sector of the Norne Field Using the Ensemble Kalman Filter
Authors: Szklarz S. P. , Hanea R. G. , Peters E. 
Published: September 2011

Abstract
In the history matching process reservoir parameters are estimated so they can be further used in a simulator to reproduce the past behaviour of the reservoir. During the last two decades the methodology evolved from manual methods to computer assisted procedures which can handle larger amounts of data. Now, when the computational power has increased enough, it is possible to perform more complicated computations and use more advance methods and at the same time choose more realistic simulation models. In spite of that, the field cases which are chosen to history match, even if more realistic they often are still synthetic. Therefore, the history matching procedure has been applied as a real case study based on Norne Field located near the Norwegian coastline. The preliminary results and the experience of handling realistic dataset are shared in this paper. The Ensemble Kalman Filter, which is recently a very popular method, has been chosen to match the well production rates and bottom-hole pressures to the real observations acquired in the segment of the field. Within the numerical experiment, permeability and porosity were estimated. Obtained results are a basis for continuation and the further improvement of the history matching process of the Norne Field. In addition, the issues encountered during the study are discussed i.e. the treatment of the flow conditions on the segment boundary and construction of initial ensemble.
Use of Pressure-Rate Deconvolution to Estimate Connected Reservoir Drainage Volume in Naturally Fractured Unconventional Gas Reservoirs from Canadian Rockies Foothills
Authors: Chen Andrew , Jones Jack R. 
Published: September 2011

Abstract
A number of successful case studies are presented in this paper to demonstrate the use of the pressure-rate deconvolution approach to estimating drainage areas for wells completed in some of the naturally fractured tight gas reservoirs of the Canadian Rockies Foothills. This study covers the application of deconvolution to two key carbonate stratigraphical horizons in the area: the Triassic Baldonnel and the Permo-Carboniferous Taylor Flat formations. Our original application of pressure-rate deconvolution was to wells in a major Cretaceous-aged sandstone member, the Cadomin-Nikanassin horizon. This process and results of this original application wil be documented and presented in a separate publication (Jones and Chen, 2011). In these structural plays, the matrix rock properties controlling the gas storativity of these formations are low with porosity between 3% and 6%. Correspondingly matrix rock permeability is also low with values between 0.01 and 0.1 md. However, all of these formations have been thrusted, overturned and have been subjected to reverse faulting. These diagentic factors have created swarms of natural fractures which control flow rates and may define rock volumes connected to individual wells.
In each well, a pre-production short flow test for each is performed with the intent of ensuring acceptable flow rates and to scope facility design. At this stage of early development, initial gas in-place (IGIP) estimates are derived from geophysical mapping mainly with plans to calibrate this IGIP number through the application of gas material balance, rate-transient analysis and/or simple late-time rate decline.
In recent years, the pressure-rate deconvolution approach has been successfully applied to many of these reservoir pools. The rate history data is available in the early stage of production, which is integrated with pressure buildup data collected later in the production life of a well during annual or routine, relatively short shut-in periods. Application of deconvolution in this paper is aimed at detecting early signs of pseudo-steady state pool depletion and to estimate the connected drainage volume.
The case studies presented here compare the deconvolution drainage volumes with the estimates from volumetric IGIP, gas material balance, and rate-transient analysis. The procedures help calibrate and/or reconcile geoscience defined volumetric resource sizes, map remaining reserves and possible infill-drilling opportunities.
Underground Natural Gas Storage in the UK: Business Feasibility Case Study
Authors: Escobar Esther , Arteaga Gerardo , Kemp Alexander 
Published: September 2011

Abstract
Currently the United Kingdom has the lowest natural gas storage rate in Europe although this is set to increase. The UK Government is committed to an increase in gas storage infrastructure by facilitating its construction, through reforms to the planning and licensing regime. The Government considers that the key to security of supply lies with a regulatory framework that provides incentives for commercial storage and with liberalisation of the gas market in Europe.
However, there have been growing doubts from investors regarding the profitability of projects promoted by the UK for underground gas storage, leading to possible delays in some of the planned gas storage schemes that have been announced, thereby compromising the security of gas supply in the UK.
The purpose of this case study is to investigate and determine the economic feasibility of a gas storage project in a depleted gas reservoir in the UK. The study analyses economic considerations in a hypothetical depleted gas reservoir-based storage facility.
An economic valuation was carried out by means of seasonal values, also known as intrinsic values, using pairs of natural gas forward prices. Subsequently, a project cash flow, linking technical and economic variables, was built to compute the project's NPV and to perform stochastic optimisation and forecasting modelling. The research also involved a statistical analysis of the UK natural gas market from 1998 to 2009.
Project outcomes established that in order to achieve the profitability of the project, relatively high price spreads are required. The analysis of the UK market shows that adequate spreads have scarcely occurred in recent years. Companies may thus delay the development of gas storage facilities and the UK government may have to offer incentives to procure the desired results.
Evaluation of Three-Phase Relative Permeability Models for WAG Injection Using Water-Wet and Mixed-Wet Core Flood Experiments
Authors: Shahverdi H. , Sohrabi M. , Fatemi M. , Jamiolahmady M. , Irelan S. , Robertson G. 
Published: September 2011

Abstract
Three-phase flow occurs during many important processes in oil reservoirs including tertiary gas and water-alternating-gas (WAG) injection. Accurate estimation of three-phase relative permeability (kr) is required to describe and predict the behaviour of these multi-phase flow conditions. The current approach in the oil industry for simulation of WAG experiments is to use two-phase relative permeability data to generate three-phase kr values by using correlations (e.g. Stone1, Baker, etc) available in commercial reservoir simulators.
In this paper, we evaluate the performances of the existing three-phase relative permeability models against experimental data. Two sets of WAG experiments were carried out by performing core flood experiments on a water-wet and a mixed wet core using low IFT oil/gas fluids. The results show that choosing inappropriate three-phase kr model in simulation of the WAG experiments can lead to large errors in prediction of fluids production and pressure. The predictions made by the existing models can be very variable and various models can predict vastly different 3-phase kr values from the same 2-phase data. While some models perform better than others, all of the 3-phase kr models examined in this study fail to predict the continued production of oil after the breakthrough of the gas which is one of the features of gas and WAG injection experiments at low gas-oil IFT (interfacial tension). The resulted three phase relative permeability obtained from WAG experiments revealed strong cyclic hysteresis for oil, water and gas relative permeabilities in both water-wet and mixed-wet systems.
Our results highlight some serious shortcomings of the existing hysteresis models. Comparison of the kr hysteresis observed for water-wet and mixed-wet WAG experiments demonstrates significant differences between the results obtained for the two wettability conditions which demonstrates the impact of wettability on three-phase flow during cyclic injection of water and gas and the importance of performing these experiments under representative wettability of the reservoir.
The results clearly demonstrate the need for improved models and methodologies for obtaining three-phase kr and also kr hysteresis especially for WAG injection.
Estimating Facies Felds using the Ensemble Kalman Filter and Distance Functions–Applied to Shallow-Marine Environments
Authors: Lorentzen Rolf J. , Nævdal Geir , Shafieirad Ali 
Published: September 2011

Abstract
The ensemble Kalman Filter (EnKF) is one of the most promising tools for assisted history matching of reservoir models, and it has in particular proven to work well on cases where petrophysical properties are modeled using Gaussian random fields with variogram models. However, many operative oil and gas reservoirs have challenging complex geological structures. These structures typically have rapid spatial variations in the petrophysical properties (e.g., permeability and porosity). The consequence of applying the EnKF directly on such reservoirs is that the characteristics of the fields are lost, i.e., sharp gradients are smeared out.
In this paper we propose a method where distance functions are used to estimate an arbitrary number of facies types. A distance function is defined as the shortest distance between a given position in the field and the boundary separating facies types. The idea behind this approach is that distances have smooth properties, and the distribution of the ensemble in a given gridblock is therefore in agreement with the EnKF Gaussianity assumptions. The distances are then updated using the EnKF, and converted to petrophysical parameters when the reservoir simulator is run to the next assimilation time. One distance function is used for each facies type. The approach is flexible and simple, and possesses several advantages compared to other existing methods: There is no restrictions on the structure of the facies field to be estimated.The methodology is able to update variations in the petrophysical parameters within each facies type.The input for the method are facies realizations that can be generated with any preferred geostatistical tool.We ensure that the updated fields always are facies realizations.We ensure conditioning of the correct facies types at the well location, both initially and during the assimilation steps.The method does not involve complex modifications of the standard EnKF equations.
Additional improvements in the quality of the updated facies fields are obtained by proper handling of the distances close to the reservoir boundaries, and conditioning on specific statistical measures to better preserve prior information about the field properties.
We demonstrate the methodology on a field with shallow-marine environment characteristics. The conclusions from the example are that the history match is improved, uncertainty is reduced and the method always returns facies realizations with geological authenticity.
Validation of THAI Bitumen Recovery Using 3D Combustion Cell Results
Authors: Greaves M. , Dong L. L. , Rigby S. P. 
Published: September 2011

Abstract
Rigorous validation of a simulation model of the THAI –Toe-to-Heel Air ijection process has been performed using results obtained from a 3D combustion cell experiment on Athabasca Oil Sands. The numerical model includes a new kinetics formulation, based on the Athabasca thermal cracking kinetics scheme proposed by Phillips (1985). The kinetic model excludes low temperature oxidation, since THAI operates in a high temperature oxidation mode. Excellent agreement was obtained between the predicted and experimental oil production rate, and there was generally a good match obtained for other dynamic variables, including the residual coke profile, produced oxygen, and peak combustion temperature. The numerical model provides a fundamental platform for upscaling to field scale, that will enable fine scale details of the process to be captured.
Simulations were performed under dry in situ combustion conditions at the high air injection fluxes used in the experiment. Under these conditions, vertical-plane temperature profiles in the sandpack confirm that the combustion front is quasi-vertical and forward leaning in the direction of the heel of the horizontal producer well. The shape of the combustion front was predicted more accurately from horizontal-plane profiles, which showed that there was no oxygen in regions ahead of the combustion front. Oil displacement occurs mainly by gravity drainage, but pressure draw down in to the horizontal producer well below the Mobile Oil Zone (MOZ) is also significant. Various zones that develop during the in-situ combustion process include a ‘Steam Zone’, and this is located upstream of the Mobile Oil Zone (MOZ). All of the mobilized oil is produced from the MOZ, which comprises two regions. The first part contains oil produced by thermal cracking of the heavy residue and vaporized ‘lighter oil’. The main bulk of the oil produced in THAI comes from the second region of the MOZ, containing ‘banked’ original oil. The oil which is eventually produced is partially upgraded oil, due to the thermally upgraded and ‘lighter oil’ fractions mixing with the original oil when they enter the horizontal producer well.
Influence of Lumping and Equation of State Tuning Methods on the Sub-Salt Reservoirs Simulation
Authors: Mello S. F. , Ligero E. L. , Scanavini H. F. , Schiozer D. J 
Published: September 2011

Abstract
The Brazilian pre-salt oil reservoirs contain a considerable amount of methane, CO2 and volatile fractions under high pressure. Several authors suggest that the compositional reservoir simulation is fundamental for the description of their properties and prediction of oil production. Although this technique improves the quality of reservoir management, due to computational limitation, simplifications of fluid data are often recommended, affecting the quality of the compositional simulation. Petroleum reservoir behavior cannot be simulated in the most accurate way using present day computational resources. Simplifications such as lumping and tuning of equation of state (EOS) to describe mixtures have influence on the phase behavior. Fluid characterization becomes an important source of uncertainties in reservoir simulation because PVT data tuning is an inverse problem with multiple possible answers. The objective of this study was to show the impact of the description of the oil behavior under typical Brazilian sub-salt conditions considering oil production and computational effort. This was done through the study of EOS and comparison of the complete fluid with the lumped fluid descriptions. Since simplifications are adopted and PVT data-handling errors are introduced, it was necessary to detect and minimize them. The analysis of this study used comparisons of phase envelopes, MMP and reservoir simulations in a synthetic model. The studied model was based on the second model of SPE 10th comparative study, heterogeneous, using oil similar to that found in the Brazilian pre-salt, with 42° API, 3.55% molar CO2, and GOR 132.9 ft3 std/ft3. This work emphasizes the importance not only of experimental data quality but also shows the impact of the choice of regression and lumping methods. It also shows the importance of fluid modeling to obtain reliability in the reservoir simulation process.