bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reducing Reservoir Uncertainties Using Advanced Wireline Formation Testing
Authors: Loi D. , Mazzoni S. , venturini S. , Baio C. , Borghi M , Baldini D. , Italiano F. , Cantini S. 
Published: June 2012

Abstract
Several offshore gas fields are present in Adriatic Sea (Italy), producing since the 60s from multilayer metric sand reservoirs. The declining production in these mature fields is normally offset by drilling new deviated wells. Recent technology evolution shifted the focus from metric reservoirs to thinly laminated intervals (thin beds), until now not produced due to difficulties in identifying gas bearing zones.
While gas identification in metric reservoirs can be normally achieved with standard petrophysical measurements, thin beds are challenging since lamination thickness is half inch or less and even advanced petrophysical logs struggle in discriminating gas from water in this environment. Conventional pressure gradient approach also does not work, since thin beds are often overpressurized and pressures are supercharged due to low mobility.
A new wireline formation testing approach for thin beds to discriminate gas from water zones was introduced, using a dual packer string with downhole fluid analysis capabilities, including fluid density measurement. This provided the possibility of testing very low permeability zones with high uncertainties in saturations. Dual packer tests were also successfully carried out in the underlying shale formation never considered before a real reservoir, revealing potential for gas production. The possibility to verify gas presence in zones with high uncertainties saved the cost of multiple well tests, optimized the completion strategy of the different reservoirs and allowed to increase the field production and reserves, reducing at the same time uncertainties in reservoir model.
Four jobs with dual packer and downhole fluid analysis to test thin beds were performed so far in Barbara NW, Barbara and Clara Fields, resulting in added gas reserves estimated in 2 Billions Sm3 and gas production higher than the one at fields startup several years ago. This is a remarkable result for development wells in a mature environment (balanced exploration), maximizing asset value. Based on these results, several gas fields producing today from metric reservoirs will be revisited in the very near future in order to start production from thin beds, untouched until now, with the advanced wireline formation testing approach described in this paper playing a key role.
Fracture Characterization Through Rate Correlation Analysis
Authors: Heffer Kes 
Published: June 2012

Abstract
Statistical correlations in flowrate fluctuations between wells from many fields appear to bear out the expectation that the hydraulic conductivities of faults and fractures in reservoirs can be influenced by geomechanical perturbations due to production operations: the fluctuations are characterised by high correlations over very large separation distances between wells; and those correlations appear to be stress-related and fault-related. An entirely separate relationship derived from observations in multiple fields is a strong bias of directionalities shown by injected fluids towards the local orientation of modern-day major principal horizontal principal stress axis (SHmax). These two sets of independent field observations provide mutually supporting observational evidences for the general geomechanical sensitivity of faults and fractures. However, whilst peaks in flowrate correlations are observed at about 30° to SHmax, the preferred flooding directionalities are at smaller angles to SHmax. A recently proposed machanism is able to explain the orientational relationships in both sets of data. It involves interacting, stress-aligned, compliant micro-cracks near a critical density; there is a large background of observations of shear-wave splitting in many types of formations that supports the prevalence of such micro-cracks. As a practical low-cost tool, analysis of flowrate correlations can provide valuable information about the major reservoir pathways as an adjunct to reservoir characterisation studies. This information can aid history-matching of reservoir models, particularly those involving fractures. The technique is also well-suited to monitoring reservoir behaviour in time-lapse fashion.
A Proposed Workflow for Disposal of CO2 using CO2 Hydrate
Authors: Rajnauth J. 
Published: June 2012

Abstract
Carbon dioxide (CO2) is an important greenhouse gas because it transmits visible light but absorbs strongly in the infrared. It is mainly generated from the combustion of fossil fuels or vegetable matter, among other industrial processes such as cement production and ammonia plants. CO2 emitted from burning fossil fuels is believed to be a major contributor to the amount of CO2 levels in the atmosphere contributing to global warming.
Hydrate technology can be used to capture CO2 gas in the form of hydrates. In this technology CO2 and water are combined at certain conditions of temperature and pressure to form a hydrate, and then transported and released at great depths into the ocean. Disposal of CO2 in the form of hydrates in the sea is a great potential as the ocean is vast and occupies 70% of the earth&apos;s surface. Numerous power plants and petrochemical plants are located near the coastline and hence there is easy access to the ocean. The CO2 hydrate formation as a CO2 disposal method may potentially offer significant savings in CO2 disposal because of minimal cost of CO2 capture.
This paper proposes a work flow for disposing of CO2. The model describes the sequence of operations for CO2 capture and disposal using CO2 hydrate. A typical example would be used to describe the workflow from CO2 emitted to CO2 hydrate disposal. CO2 hydrate is denser than seawater and therefore CO2 hydrate deposited in the ocean will sink to the seabed as long as the disposal site is within the hydrate formation envelope.
Understanding the True Potential of a Major Reservoir Sabriyah (Upper Burgan) of Kuwait Oil Company
Authors: Al Shammari Hanaa , Bora Anup , Singh B B , Mishra Kumar 
Published: June 2012

Abstract
Kuwait Oil Company is presently working on number of fronts to increase its reserve base to meet the future strategic requirements of the country. The major challenge is to continuously work on improving the overall recovery from the existing reservoirs. For achieving this goal, Reservoir Management Technical Limit study (RMTL) process was undertaken to estimate the true potentials of a number of reservoirs of KOC which are under various stages of development.
RMTL is a structured, facilitated, documented process at which multi-disciplinary teams and independent experts review the depletion plan for a reservoir and identifying reserve growth opportunities to its technical limit. The RMTL study was carried out to assess the potential of Sabriyah (Upper Burgan) reservoir in North Kuwait asset of Kuwait Oil Company. This reservoir is currently in the second stage of development with activities like development drilling, water injection for pressure maintenance.
In order to assess the viability of different EOR processes and eliminate technically unviable process, the analytical screening was done. Finally, a few representative pattern elements from the full field simulation model were extracted for use in the EOR screening. The EOR screening exercise has shown potential for low salinity water flood, surfactant polymer and potentials for miscible CO2 injection. Incremental recovery factors up to 13% are predicated compared with conventional water flooding. These studies have given a direction to the company to decide on economically viable EOR processes in different reservoirs of Kuwait.
Multidisciplinary Approach for Novel Application of Formation-pressure-while-drilling Service in High Temperature (160 Deg.C) Low Permeability Carbonate
Authors: Bruni Corrado , Odumboni Idowu , Sellami Besma , Turner Marcus , Sanguinetti Marco , Kazmer Jorge 
Published: June 2012

Abstract
The Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with a measured matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996.
Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, well-to-well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline (WL) formation testers for the following reasons: Severe depletion and well deviation causing differential stickingHigh temperatures (150 to 195° C) at the limit of tool electronicsLow permeabilityFractures and breakouts that can impact seal success
This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data, and influence on seal success with probe vs. packer elements, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects.
While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Pre-run wireline petrophysical data were gathered to characterize the Petrophysical properties of the reservoir and to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation and to confirm the stratigraphic dipping of the structure. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts.
This novel approach resulted in 100% seal success, &gt;50% improvement. Four days of rig time were saved, and the required data were obtained.
Use of Water Chemistry Data in History Matching of a Reservoir Model
Authors: Arnold D. , Vazquez O. , Demyanov V. , Christie M. A. 
Published: June 2012

Abstract
Produced Water Chemistry (PWC) has been included in the history matching of reservoir simulations. Generally, in conventional history matching, the water chemistry is not considered as an extra constraint. The chemistry of the different types of water in a reservoir, such as aquifer, connate and seawater is very different, and can be traceable. Produced Water Chemistry is the main source of information to monitor scale precipitation in oil field operations.
The objective of this paper is to evaluate the effect of adding produced water chemistry information as an extra constraint history matching a modified version of the PUNQ-S3 reservoir model. The PUNQ-S3 model is a synthetic benchmark case that has been used previously for history matching and uncertainty quantification. Conventional historical production data (gas, oil rates and pressure) from six production wells are supported by the water chemistry tracer data from the wells that produce water in the history period. The different types of water are traced through their distinctive chemistries, namely aquifer, connate (formation) and sea (injection) water. Geological model is matched by varying porosity and permeability, both horizontal (kh) and vertical (kv) according to the prior beliefs about the reservoir geology (layering, spatial correlation and anisotropy).
Two history matching (HM) scenarios are considered: including and not-including the Produced Water Chemistry (PWC) as an extra matching constraint. Stochastic Particle Swarm Optimization (PSO) algorithm is used to generate ensembles of history matched models, which characterise the uncertainty of the reservoir prediction. Comparison of the two scenarios reveals potential value of adding PWC data in history matching that allows achieving better matched models and ensuring diversity of HM models, which is essential for robust uncertainty quantification of the predictions.
Dynamic Capillary Pressure Curves from Pore-Scale Modelling in Mixed-Wet Rock Images
Authors: Zhou Y. , Helland J. O. 
Published: June 2012

Abstract
In reservoir multiphase flow processes with high flow rates, both viscous and capillary forces determine the pore-scale fluid configurations, and significant dynamic effects could appear in the capillary-pressure/saturation relation. We simulate dynamic and quasi-static capillary pressure curves for drainage and imbibition directly in SEM images of Bentheim sandstone at mixed-wet conditions by treating the identified pore spaces as tube cross-sections. The phase pressures vary with length positions along the tube length but remain unique in each cross-section, which leads to a nonlinear system of equations that are solved for interface positions as a function of time. The cross-sectional fluid configurations are computed accurately at any capillary pressure and wetting condition by combining free energy minimization with a menisci-determining procedure that identifies the intersections of two circles moving in opposite directions along the pore boundary. Circle rotation at pinned contact lines accounts for mixed-wet conditions. Dynamic capillary pressure is calculated using volume-averaged phase pressures, and dynamic capillary coefficients are obtained by computing the time derivative of saturation and the difference between the dynamic and static capillary pressure. Consistent with previously reported measurements, our results demonstrate that, for a given water saturation, simulated dynamic capillary pressure curves are located at a higher capillary level than the static capillary pressure during drainage, but at a lower level during imbibition, regardless the wetting state of the porous medium. The difference between dynamic and static capillary pressure becomes larger as the pressure step applied in the simulations is increased. The model predicts that the dynamic capillary coefficient is a function of saturation and independent of the incremental pressure step, which is consistent with results reported in previous studies. The dynamic capillary coefficient increases with decreasing water saturation at water-wet conditions, whereas for mixed-to oil-wet conditions it increases with increasing water saturation. The imbibition simulations performed at mixed-to oil-wet conditions also indicate that the dynamic capillary coefficient increases with decreasing initial water saturation.
The proposed modelling procedure provides insights into the extent of dynamic effects in capillary pressure curves for realistic mixed-wet pore spaces, which could contribute to improved interpretation of core-scale experiments. The simulated capillary pressure curves obtained with the pore-scale model could also be applied in reservoir simulation models to assess dynamic pore-scale effects on the Darcy scale.
History-matching with Ensemble-Based Methods: Application to an Underground Gas Storage Site
Authors: Gervais V. , Le Ravalec M. , Heidari L. , Schaaf T. 
Published: June 2012

Abstract
This paper shows the application of two ensemble-based assimilation methods, the Ensemble Kalman filter (EnKF) and the Ensemble Smoother (ES), to constrain an underground gas storage site to well pressure data. The EnKF is a sequential data assimilation method that provides an ensemble of models constrained to dynamic data. It entails a two-step process applied any time data are collected. First, production responses are computed for every model within the ensemble until the following acquisition time. Second, models are updated using the Kalman filter to reproduce the data measured at that time. The EnKF has been widely applied in petroleum industry. More recently, the ES was successfully applied to a real field case. This method is also based on the Kalman filter, but the update is performed globally over the entire history-matching period: values simulated at assimilation times are considered all together in the update step. The uncertain parameters considered here are the porosity and horizontal permeability values populating several layers of the geological model. Applying both the ES and EnKF methods, the spread within the ensembles is reduced and the predictions based on the ensembles of updated petrophysical distributions get closer to the pressure data corresponding to the history-matching and prediction periods.
A Comparative Study of Reduced Variables Based Flash and Conventional Flash
Authors: Michael L. Michelsen , Yan Wei , Stenby Erling H. 
Published: June 2012

Abstract
Speeding up flash calculation is a central issue in compositional reservoir simulations since phase equilibrium calculation is the most time-consuming part in those simulations. The reduced variables methods, or the reduction methods, reformulate the original phase equilibrium problem with a smaller set of independent variables. Various versions of the reduced variables methods have been proposed since the mid 80’s. The methods were first proposed for cubic equations of state (EoS) with zero binary interaction parameters (BIPs) and later generalized to situations with non-zero BIP matrices. Most of the studies in the last decade suggest that the reduced variables methods are much more efficient than the conventional flash method. However, Haugen and Beckner questioned the advantages of the reduced variables methods in their recent paper (SPE 141399). A fair comparison between the reduced variables based flash and the conventional flash is not straightforward since the former is difficult to be formulated as unconstrained minimization and involves more complicated composition derivatives. With the recent formulations by Nichita and Graciaa (2010), it is possible to code the reduced variables methods without extensive modifications of Michelsen’s conventional flash algorithm. A minimization based reduced variables algorithm was coded and compared with the conventional minimization based flash. A test using the SPE 3 example showed that the best reduction in time was less than 20% for the extreme situation of 25 components and just one row/column with non-zero BIPs. A better performance can actually be achieved by a simpler implementation directly using the sparsity of the BIP matrix.
Improved Mobility Calculation for Finite Element Simulation
Authors: Abushaikha Ahmad S. , Blunt Martin J. , LaForce Tara , Gosselin Olivier R. 
Published: June 2012

Abstract
We implement a novel up-winding scheme for finite element mobility calculation using the computed velocities in a finite element finite volume (FEFV) unstructured-mesh simulator. In FEFV numerical method, the pressure and transport equations are decoupled. The pressure is calculated using finite elements, and the saturation is calculated using finite volumes. Each element is shared between several control volumes -- three for triangles and four for tetrahedrals. Consequently, the saturations used in calculating element mobilities &#45; hence updating pressure &#45; are unclear. Some researchers use the average value between the elemental control volumes, or the integration points of the finite elements. For three-dimensional spherical flow, this does not produce accurate saturations profiles when compared to the Buckley-Leverett reference solution.
In this paper, we present a new formulation to calculate the FE mobility. We use the velocity vector, which is piece-wise constant in first order elements, to find the upstream saturation–where the tail of velocity vector intersects an element. This novel approach produces more accurate saturation profiles than previous conventional method, and it better models multi-phase displacements in complex reservoirs. It can be easily implemented in current FEFV based simulators.
Considerations on of Drillpipe Dynamics with Actual Drilling Data
Authors: Inoue Tomoya , Kyo Masanori , Sakura Koji , Senga Hidetaka 
Published: June 2012

Abstract
The scientific drilling vessel Chikyu was designed to have the capability to drill down to 10,000 m total vertical depth and to obtain core samples. To reach such deep drilling and to recover scientifically worthy core samples, it is important to know the drill pipe dynamics using the actual drilling data for strength evaluation of the drill pipe and for control of a drill bit.
To reach such deep drilling, a fine strength evaluation is mandatory because there is little margin. So, the estimation of dynamic tension due to vessel heave motions is necessary. During the design phase, strength evaluation of the drill pipe is conducted under several assumptions. To ensure the strength of the drill pipe, it is important to utilize data acquired from actual drilling operations and to verify the analysis model. Furthermore the core recovery rate is affected by the variation of the weight on bit caused by the propagation of the vessel heave motions. Therefore, a heave compensating system will be used and it is very important to evaluate the performance.
Thus, the authors have acquired the drilling data including the vessel motions, the hook load variations and the motion of the heave compensator. And analysis with actual drilling data shows the dynamic tension that was actually exerted and the basic performance of the heave compensator. This paper described that the dynamic tension considering influence of the compensator and also the performance of the heave compensator from the viewpoints of following capability including a phase difference. Actual drilling data provided the worthy information on the drill pipe dynamics. The considerations will be utilized for future operations such as Tohoku Earthquake Drilling Program and Nankai Trough drilling programs and also for future technical development.