bluuebunny/crossref_metadata_2025_split huggingface dataset:
Vector Scanning: Hydro-fracture Monitoring With Surface Microseismic Data
Authors: Ma Licheng , Wang Lei , Shen Yiping , Zhou Yongsheng , Liang Beiyuan 
Published: June 2012

Abstract
For monitoring hydraulic fracture (HF) in oil/gas fields the most reliable seismic method to avoid the adverse effect of strong surface noises is using downhole microseismic surveys. Nevertheless, downhole measurement is more expensive and limited by the availability of suitable boreholes in the vicinity of the hydro-fracture site.By all means seismic surveys conducted on land surface bear the largest flexibility and are more economic than downhole measurements. As a significant progress in hydro-fracture monitoring Duncan et al developed a surface monitoring system using seismic arrays centered at the hydro-fracture point. This monitoring method requires large-scale and prolonged operations; thus the cost-effectiveness is still less than ideal. In this paper we present a novel approach for land monitoring of hydro-fractures that uses only sparse seismic stations far from fracturing vehicles; and the total number of seismic stations is much less than previous approaches; so that the cost-effectiveness is significantly improved. With a small-scale seismic array on land surface we have monitored the hydro-fracture processes using a vector scanning technique for imaging hydro-fractures and determining rupture focal mechanisms. The applications of this technique to a synthetic data set based on numerical modeling and the real-world field data show that it is able to trace the tempo-spatial development of hydro-fractures even when the signal to noise ratio (S/N) is lower than 0.5. The vector scanning technique significantly shows the fracture imaging quality, and provides us a costeffective approach for monitoring flow-enhancement hydro-fracture processes.
In-Depth Evaluation of Deep-Rock Hydrajet Results Shows Unique Jetted Rock Surface Characteristics
Authors: Stockhausen Harald W. , García Sanchez Daniel G. , Luongo Sergio A. , Surjaatmadja Jim B. , Loghry Ray A. 
Published: June 2012

Abstract
The use of hydrajetting for perforating of wells has been commonplace since the 1960s. During those early years, wells were relatively shallow, and jetting success was consistently demonstrated. However, as wells became deeper, where rock formations tend to be harder, hydrajetting performance became less dependable; subsequently, stimulation failures more often occur as a result of the lack of fracture initiation.
To remedy this situation, a series of tests were performed to define new best practices for hydrajet perforating of hard rock under high ambient pressure environments. Various rocks were subjected to these tests, which were performed using different jetting pressures and different abrasives. The perforation surfaces were then dissected and evaluated using photographic and chemical means. Further assessments were then made to determine what actually occurred during the hydrajetting process.
This paper discusses various test results, and new constraints for hydrajetting are defined and presented.
Condensate Recovery from a Fractured Carbonate Field
Authors: Paraschiv Catalin , Abdev Joseph , Clemens Torsten 
Published: June 2012

Abstract
Fractured reservoirs are characterised by a large difference in permeability of the fracture and matrix system. Usually, the matrix contains the bulk of the hydrocarbons while the fractures are the flow paths. These characteristics are challenging for projects aiming at increasing hydrocarbon liquid recovery from gas condensate fields by gas injection. While in fractured oil reservoirs capillary forces (imbibition) or gravity forces can be utilised to improve oil recovery, for gas injection into gas condensate reservoirs, these forces are less important.
The recovery mechanisms were investigated using the properties of a rich gas condensate field located in the Middle East. A fine grid sector simulation model was created in which the fractures and matrix were introduced explicitly.
Without taking diffusion into account, the injected gas breaks through at the producer very fast. The concentration in the produced gas is closely linked to the effective permeability of the fracture divided by the effective permeability of the matrix.
However, taking diffusion into account, the increase in injected gas concentration is much slower. The speed of the increase (for the same pore volume injected) depends on matrix porosity, velocity of the front, fracture spacing and permeability contrast.
The molecules of the injected gas are diffusing into the matrix while the components of the reservoir gas are diffusing towards the fracture. The various components have different diffusion coefficients. Dependent on the injection gas, the dew point pressure in the matrix can be reached (despite the reservoir pressure being constant) and condensate drops out. Hence, the condensate recovery depends on the injected gas.
The results of the study show that neglecting diffusion in fractured reservoirs can result in errors in the condensate recovery of more than 50 %. In addition, the shape of the condensate recovery curve will be incorrect if diffusion is not accounted for.
Predicting water in the crest of a giant gas field: Ormen Lange Hydrodynamic Aquifer Model
Authors: Boya Ferrero M. , Price S. , Hognestad J. 
Published: June 2012

Abstract
Hydrodynamic aquifer conditions have been described in many basins around the world since first introduced by Hubbert1 in 1953. The hydrodynamic aquifer concept in Ormen Lange has been assessed using iso-potential mapping1 and dynamic simulation of the fluid fill development (i.e. imbibition) over geological time. Simulation shows2,3 the hydro-dynamically tilted/stepping contacts depend on rate of water flow across the aquifer, stratigraphic baffling and faulting, effective aquifer area and reservoir quality (NTG and effective permeability). The role of sealing faults over geological time scale is downplayed in terms of justifying the fluid distribution. Baffling during production is, however, expected. In Ormen Lange the hydrodynamic aquifer has pushed the gas from the crest of the structure into the south of the field leaving behind a northward-thickening prism of residual gas which is imaged by a seismic DHI. Confirmation of the hydrodynamic aquifer scenario in this field was achieved after drilling an appraisal well in the north of the structure that corroborated fluids (water with residual gas) and pressures as prognosed by the hydrodynamic aquifer model.
New Data Retrieval Application Significantly Improves Asset Management in Digital Oilfields with Intelligent Completions
Authors: Allen Cifford , Smith Robert 
Published: June 2012

Abstract
In digital oil fields in which intelligent completions are used, information that can be provided by the intelligent completion technology is increasing in importance, as intelligent well completions can minimize the need for additional custom data-gathering solutions. Thus, industry-data interfacing standards for multiple devices and systems can be reduced. For assets using intelligent completions, solutions are attained by a combination of subsurface and surface or subsea sensors provided by several vendors.
Challenges arise when attempting to manage the interfaces required for providing real-time data from all points of interest (i.e., subsurface choke positions, flow, pressures and temperatures, wellhead positions, subsea facility readings, etc.). The design and implementation of an integrated data-applications system that can integrate data from multiple workflow sources for the purpose of maximizing field performance is the focus of this paper. The asset optimization applications acquire operating parameters from all points of interest, making them available to software modules designed to estimate key wellperformance indicators.
The asset-optimization application discussed here is an integrated system that performs five services: A data-interfacing methodology acquires data from multiple sources or directly from downhole devices.The integration service converts the subsurface and surface data to engineering units of measured well parameters.The well performance service uses well PVT and device-integration service values to execute complex calculations, like virtual flow metering, water-cut estimates, etc.The human/machine/interface service provides visualization, trending, and querying.The connectivity service facilitates structured data transfer to field historians.
The paper will explain how the system works and its implementation into fields of different scales and types to reduce information technology (IT) customization, simplify interfacing of multiple devices or systems, and accommodate evolutions in IT. Additional system benefits that include more efficient management of real-time data security, quality, redundancy, and mirroring will also be provided.
Understanding Uncertainties in Deepwater Depositional Facies Modeling for Better Reservoir Conditioning
Authors: Chen Jiajie (Jeff) 
Published: June 2012

Abstract
In deepwater reservoir modeling, the proportions of various facies being modeled have a significant impact on the distribution of reservoir properties, total reserve, reservoir connectivity, and hence recoverable reserve. Generally, facies modeling can be achieved by deterministic or stochastic approaches, or a combination of both. When seismic data have sufficient quality or resolution, the data may serve as certain reservoir property indicators, and the approach for facies modeling can be more deterministic. When seismic data are not available or do not have sufficient resolution, a stochastic approach is usually needed. In either case, the uncertainties in facies distribution must be fully assessed. This paper presents a case study and workflow in which different sand-shale proportions (more optimistic, basic, and less optimistic) are considered in facies modeling, in order to investigate the range of deepwater turbidite facies distribution and its effect on reservoir property variations. The facies models are constructed by different methods, including deterministic, stochastic, and a combination of both. Comparison of the deterministic and stochastic models provides certain insight into the distribution of depositional facies. Further, in each facies scenario, the range of reservoir property distribution is assessed. In addition, for different reservoir zones, the ranges of oil-water contacts are incorporated in the reservoir model. As a result, the entire spectrum of in-place hydrocarbon volumes is captured, and various stacking patterns as well as connectivity issues can be conditioned in the simulation model, leading to a more robust understanding on the resource to be developed.
Reducing the Dimensionality of Geophysical Data in Conjunction with Seismic History Matching
Authors: Rezaie Javad , Sætrom Jon , Smørgrav Eivind 
Published: June 2012

Abstract
Seismic history matching (HM) has attracted increasing attention the last few years. As more repeated seismic surveys are acquired, the more apparent the shortcomings in modern HM tools and algorithms become. A common conception seems to be that the amount of data represented by geophysical observations and the complexity of working with 3D fields make the updating procedure hard. We investigate the nature of geophysical observations from a HM point of view by testing several data reduction techniques such as Principal Component Analysis (PCA), regression techniques such as forward stepwise, as well as state-of-the-art techniques based on neural networks. We argue that simulated geophysical fields from the prior models are prone with spatial correlations and that their information content and effective dimensionality is much smaller than the dimensionality of the observed field. The techniques are tested on a reservoir model of an anonymous North Sea oil field, using the seismic time shift, i.e. the difference travel time integrated over the reservoir between two surveys. We find that PCA is particularly promising, resulting from the versatility and robustness of the method. In practice this means that high dimensional geophysical data, e.g. 2-D seismic images or 3-D seismic cubes, can often be described using only a handful of scalars. We show how to assess the information content in the data, compress the data, and use this compressed data in a reservoir conditioning setting. The methods we present are generic; they apply equally well to all geophysical attributes regardless of representation and can be applied with any history matching algorithm, although they are mainly designed for ensemble based techniques.
Simulation of Drilling Fluid Filtrate Invasion Near an Observation Well
Authors: Chassagne Romain L. , Hammond Paul S. 
Published: June 2012

Abstract
We used a commercial reservoir simulator to study first the dissipation of aqueous drilling fluid filtrate invasion around a cased observation well in an oil-saturated formation under the action of capillary pressure, and then the interaction of a waterflood front with the cased well and remaining invaded zone. Hysteretic behavior of the capillary pressure and relative permeabilities is critically important to these processes and is taken into account using the Killough model, with the various bounding drainage and imbibition curves computed from a pore network model.
Filtrate invasion into a hydrocarbon formation influences the readings of well logging tools. Although this phenomenon has been known, and corrected for, for many years, uncertainty remains with regard to the long-time behavior of invasion around observation wells where no flow in or out of the formation occurs after completion, and also with regard to the influence of formation wettability. We find that after sufficient time the invaded zone dissipates completely in a water-wet formation, but some invasion always remains in the oil/mixed-wet case. Non-wetting-phase trapping, manifested through relative permeability hysteresis, is the cause. Because trapping affects the values and the end points of the relative permeability curves, a waterflood front passing across an observation well is more distorted in the oil/mixed-wet case. The simulation results allow us to understand how logging tool measurements made in cased observation wells are influenced by drilling fluid invasion and will therefore lead to improved interpretation. This study shows strong links between the wettability of the formation and persistence of invaded zone saturation and between invaded zone saturation and the distortion of subsequent flood fronts.
Developing a Toolbox for Evaluating Water Injection Performance on the Norne Field
Authors: Atabay Shahram , Drønen Ole Magnar , Flo Hvidsten Jon Magne , Fawke Anna 
Published: June 2012

Abstract
The Norne Field is a mature subsea oil field located on the Norwegian continental shelf and it has been on production since November 1997. The reservoir drainage strategy is mainly based on water injection with an early phase of WAG injection. Pressure support is successfully achieved, however, currently (at early tail phase), the major challenge is to increase the macroscopic (vertical and areal) sweep efficiency in the upper part of the main reservoir.
Different methods and techniques have been applied to understand the current water flow pattern in order to optimize the macroscopic sweep efficiency:
1) Review of the historical data.
2) Use of Hall plot technique to evaluate the injectivity and vertical sweep.
3) Full field and conceptual simulation models.
4) Spearman’s rank correlation to investigate injectior - producer relationships.
5) Tracer data to evaluate the areal sweep.
Improving the water injection strategy is important for maximizing the field recovery factor.
This paper presents the methods used to evaluate the water injection strategy and the results of these evaluations for improvement.
Applications of Harmonic Pulse Testing to Field Cases
Authors: Fokker Peter A. , Renner Joerg , Verga Francesca 
Published: June 2012

Abstract
Harmonic pulse testing is a well testing technique in which the injection or production rate is varied in a periodic way. The pressure response to the imposed rates, both in the pulser well and in the observer wells, can be analyzed in the frequency domain to evaluate the reservoir properties. The advantages of this type of test are that dedicated well testing surface equipment is not required and that the test can be performed during ongoing field operations. In an earlier study we demonstrated that the harmonic pulse testing methodology can be used to evaluate the effective permeability to hydrocarbons and the reservoir total compressibility even for such a heterogeneous case as in a water injection scenario. The analysis can be performed using a numerical simulator in the Fourier domain, by which heterogeneities can be explicitly taken into account. As time-stepping is not required in such a simulation, calculations are much faster than calculations in the time domain.
In the present paper we report on the application of the methodology to two field cases. The first case is a gas storage reservoir, operated with a day‒night injection‒shut in scenario. Data analysis proved that the reservoir was homogeneous and that a minor fault identified by the seismic was not hindering hydraulic communication between the pulser and the observer wells. The second case is a set of harmonic test experiments on three groundwater wells, the details of which have been published earlier together with a first attempt to interpret the data. The previous analysis was based on the hypothesis of homogeneous formation, but could not consistently explain all the measurements. With our novel methodology it was possible to investigate the effects of heterogeneity and we demonstrated that the presence of a fault zone with reduced permeability may explain the observations.
Application of Integrated Production and Asset Modeling for Sour Field Development Planning
Authors: Alkindi A. , Linthorst S. 
Published: June 2012

Abstract
A key and challenging issue in the oil and gas industry is Integrated Asset Management, which encompasses efforts from various disciplines to build a single integrated model that describes the whole system. This paper presents an integrated production model (IPM), forecasting workflow and decision making philosophy to develop two complex sour fields comprising three reservoirs in South of Oman. The study involves two sour oil reservoirs (of different PVT properties, H2S concentrations) and drive mechanisms and one sour gas condensate reservoir that is used to complement associated gas to give a constant gas rate for export. Water injection and water handling are parts of the model.
The modelling couples subsurface dynamic 3D models (built using Shell&apos;s MoReS reservoir simulator), well models and surface network (built in GAP) and the interactions that occur in the production system. The configuration involves three reservoirs, 19 oil and 3 gas producers, 12 water injectors, one production station, three separators (low, medium and high pressure) and several flow lines of different sizes. The main objective of the study is to optimize the developments of these reservoirs by assessing the best design of surface network (plant capacity). The integration allows to assess the impact of various station capacities; either liquid or/and gas, on the project profitability under different operational scenarios such as injection rate, off-take, artificial lift and well phasing and their impact on CAPEX and OPEX. The model also helps in identifying system bottle-necks, effects of back pressure, mixing of fluids and flow assurance. The use of jet pumps as artificial lift mechanism was successfully imbedded and optimized.
The paper describes the structure of the modelling, surface components, optimization strategy, benefits and challenges of IPM deployment to choose the optimum field design. The results demonstrate the importance and merit of field management in addition to accuracy and rapidness of production forecast.
Assisted History Matching Using Three Derivative-Free Optimization Algorithms
Authors: Chen Chaohui , Jin Long , Gao Guohua , Weber Daniel , Vink Jeroen C. , Hohl Detlef F. , Alpak Faruk O. , Pirmez Carlos 
Published: June 2012

Abstract
Gradient-based optimization algorithms can be very efficient in history matching problems. Since many commercial reservoir simulators do not have an adjoint formulation built in, exploring capability and applicability of derivative-free optimization (DFO) algorithms is crucial. DFO algorithms treat the simulator as a black box and generate new searching points using objective function values only. DFO algorithms usually require more function evaluations, but this obstacle can be overcome by exploiting parallel computing.
This paper tests three DFO algorithms, Very Fast Simulated Annealing (VFSA), Simultaneous Perturbation and Multivariate Interpolation (SPMI) and Quadratic Interpolation Model-based (QIM) algorithm. Both SPMI and QIM are model-based methods. The objective function is approximated by a quadratic model interpolating points evaluated in previous iterations, and new search points are obtained by minimizing the quadratic model within a trust region. VFSA is a stochastic search method. These algorithms were tested with two synthetic cases (IC fault model and Brugge model) and one deepwater field case. Principal Component Analysis is applied to the Brugge case to parameterize the reservoir model vector to less than 40 parameters.
We obtained good matches with all three derivative-free methods. In terms of number of iterations used for converging and the final converged value of the objective function, SPMI outperforms the others. Since SPMI generates a large number of perturbation and search points simultaneously in one iteration, it requires more computer resources. QIM does not generate as many interpolation points as SPMI, and it converges more slowly in terms of time. VFSA is a sequential method and usually requires hundreds of iterations to converge.
A Modified Version of the Aziz et al. Multiphase Flow Correlation Improves Pressure Drop Calculations in High-Rate Oil Wells
Authors: Al-Attar Hazim H. , Mohamed Mohamed Y. , Amin Mohamed E. 
Published: June 2012

Abstract
The prediction of multiphase pressure drop during the simultaneous flow of oil, gas and water in vertical tubing strings is crucial in the development and optimum exploitation of an oil field.
In this paper a method is proposed to improve pressure drop predictions by Aziz et al. multiphase vertical-flow correlation. This correlation is theoretically justified as compared to the traditional empirical methods. The present method suggests combining several flow pattern maps with the Aziz et al. correlation in an attempt to achieve the improvement sought. Two field data sets comprising 32 production tests gathered from three different sources in the Middle East and North Africa were used to examine the performance of the various combinations.
The results of this work indicate that the performance of Aziz et al. multiphase correlation can be best improved by replacing its original flow-pattern map with the traditional Duns-Ros flow-regime map and for both data sets used. A significant improvement has been observed giving an overall absolute average percent deviation of 2.16% compared with 5.33% for the original correlation. Also, with this combination the relative performance factor has been reduced to 1.33 from 2.90 for the original Aziz et al. correlation. The efficiency of the Aziz et al.-Duns and Ros combination at high oil production rates, when compared with the original Aziz et al. correlation, was further examined by noticing the improvement gained in statistical measures at higher levels of liquid superficial velocity.
This work represents an addition to the technology of multiphase behavior in vertical pipes and its results will help in a more accurate design of tubing strings in high-rate producing oil wells.