bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Well Pad & Completion Design for Hydraulic Fracture Stimulation in Unconventional Reservoirs
Authors: Schofield J. , Rodriguez-Herrera A. , Garcia-Teijeiro X. 
Published: May 2015

Abstract
Reservoir stimulation by means of hydraulic fracturing has enhanced the production of hydrocarbons from shale. The latest methods concentrate on reducing the detrimental interference between fractures within the same well. The theory behind this is well understood, however the concept of constructive interference between fractures in adjacent wells is not so developed.
In this paper, contemporary hydraulic fracturing techniques are numerically simulated to analyze both the rock and fluid mechanic effects on the generation of fractures within a reservoir. The techniques involve various geometrical patterns of well and fracture spacing, followed by methods of sequencing the different stages of stimulation. These methods aim to reduce the compressive stress normal to fractures and increase the size o f tensile regions between fractures in adjacent wells. To measure the performance of different methods, the simulated microseismic energy released is used to calculate the stimulated rock volume (SRV). Production profiles have been generated for several key hydraulic fracturing scenarios, with the results predominantly showing an optimum well spacing to exist.
Lessons Learned from Further Development of the Peregrino Heavy Oil Field Offshore Brazil
Authors: Haugen Einar , Østbye Nils O. , Grønvold Tore , Straith Knut , Theting Thomas G. 
Published: May 2015

Abstract
The Peregrino heavy oil field is located 85 km off the coast of Cabo Frio, Rio de Janeiro. The water depth in the area is approximately 120 m. Phase I of the development comprises a FPSO and two wellhead/drilling platforms. Production of oil started in April 2011. Statoil is operator with 60% equity and partner Sinochem holds 40%. To date, more than 80 million barrels of 14° API oil has been lifted and close to 30 development wells have been drilled. The drive mechanism of the reservoir is reinjection of produced water and pressure support from the aquifer.
The new Phase II development involves a third wellhead platform tied back to the FPSO. It targets oil resources that cannot be reached from the two existing wellhead platforms. An extensive exploratory drilling program with a total of six reservoir penetrations and a detailed data collection program were undertaken in 2011-2012. From the drilling campaign the Peregrino field was found to have a large southern extension with additional 1-2 billion barrels of oil in place that could be developed. In spite of many similarities with the geology in Phase I, the new reservoirs held a number of surprises with respect to reservoir fluid (lighter oil was found) and different reservoir properties.
This paper describes the experiences and challenges with developing this offshore heavy oil field from a subsurface point of view: These include appraisal strategy for optimum data collection, reservoir modelling, and impact on design parameters such as production capacities. Many of these challenges are generic for heavy oil fields: how to handle large amounts of water circulation, identifying reservoir data that are critical for field planning such as absolute and relative permeability. Heavy oil reservoirs with oil viscosity of several hundred centipois are usually high quality reservoirs with relatively homogenous sandstone, as is the case with the Peregrino field for the most part. This paper discusses critical factors in determining reservoir performance for a wide range of reservoir parameters, and includes a section on how this was implemented in the uncertainty analysis.
Safe water injection into the oil zone to avoid fracturing the cap rock is very important. This has been assured both through theoretical work and data from an injection well in the Peregrino field. All producers in Peregrino are horizontal wells (with open-hole gravel packs) in order to improve productivity and drainage. Flow assurance and oil-water transport in wells and flow lines are also described. Use of inflow control valves in horizontal wells have shown potential in Peregrino and will be described in the paper.
Using Tracer Data to Determine Polymer Flooding Effects in a Heterogeneous Reservoir, 8 TH Reservoir, Matzen Field, Austria
Authors: Laoroongroj Ajana , Lüftenegger Markus , Kadnar Rainer , Puls Christoph , Clemens Torsten 
Published: May 2015

Abstract
Polymer injection pilot projects aim at reducing the uncertainty and risk of full-field polymer flood implementation. The interpretation of polymer pilot projects is challenging owing to the complexity of the process and fluids moving out of the polymer pilot area. The interpretation is increasingly more complicated with the heterogeneity of the reservoir.
In the polymer pilot performed in the 8 TH reservoir of the Matzen Field in Austria, a polymer injection well surrounded by a number of production wells was selected. A tracer was injected one week prior to polymer injection. The tracer showed that the flow-field in the reservoir was dramatically modified with increasing amounts of polymers injected. Despite short breakthrough times of 4-10 weeks observed for the tracer, polymer breakthrough occurred only after more than 12 months although injection and production rates have not been substantially changed.
The tracer signal indicated that the reservoir is heterogeneous with high flow velocities occurring in high permeable layers. By injecting polymers, the mobility of the polymer augmented water was reduced compared with water injection and lead to flow diversion into adjacent layers. The tracer response showed that the speed of the tracer moving from injection to production wells was reduced with increasing amount of polymers injected.
This response was used to assess the changes of the amount of water flowing from injection to production well. After a match for the tracer curve was obtained, adsorption, residual resistance factor and dispersivity were calculated. The results showed that even for heterogeneous reservoirs without having good conformance of the pilot, the critical parameters for polymer injection projects can be assessed by analyzing tracer and polymer response. These parameters are required to determine whether implementation of polymer injection at field scale is economically attractive.
Along the flow path, an incremental recovery of about 8 % was achieved. The polymer retention and inaccessible pore volume in the reservoir was in the same range as in core floods. Incremental oil recovery owing to acceleration along the flow path was estimated at contributing to about 30 % to the overall incremental oil production due to polymer injection and 70 % to improved sweep efficiency.
Operational Challenges and Monitoring of a Polymer Pilot, Matzen Field, Austria
Authors: Lüftenegger Markus , Kadnar Rainer , Puls Christoph , Clemens Torsten 
Published: May 2015

Abstract
Four main areas of uncertainty can be described in polymer injection projects: Are we able to deliver the polymer solutions at the required quality to the wellhead?Are we able to inject polymers at the required quantity and quality?Are we producing sufficient incremental oil?Are we able to cost-effectively separate, and treat oil and water after polymer breakthrough?
The monitoring program which was developed for the polymer injection pilot aims at reducing the uncertainty and at fast identification of operational difficulties - details are described below:
Polymer quality at the wellhead: the polymer concentration and viscosity of the “mother” solution and injected polymer solution was measured at various locations in the surface facilities. A quality check of the delivered polymer, including a filter ratio test of the dissolved polymer was performed, the biological activity monitored, iron content measured and polymer solution investigated for “fish-eyes”. The monitoring program enabled us to identify challenges related to shearing the polymers after changing the operating envelope, to identify problems related to biological activity and to ensure data quality for interpretation of the pilot. Injectivity and Degradation: monitoring involved wellhead and bottom-hole-pressure measurements and repeated fall-off tests as well as visual monitoring of the polymer solutions in the well. The results showed the mobility reduction of the polymer solutions versus water mobility and an indication of induced fractures. Combining the various measurements led to identification of an operational issue: the injectivity decreased more than expected from polymer rheology and prepilot water quality assessment. The reason was the combination of polymers and biological activity in combination with fines and oil (despite being small). This challenge is currently tackled by reducing the biological activity. Incremental oil: accurate measurement of the water cut of the producing wells is key; in particular of the wells producing at water cuts above 90%. In addition, water salinity at the producing wells was measured and a repeated tracer program was set up. The results have been used to assess the reservoir architecture and incremental oil related to polymer injection. The challenges in the interpretation of the pilot related to conformance of the pilot could be resolved using this data. Polymer, oil, water treatment: the surface facilities are constantly monitored for separation efficiency and plugging owing to back produced polymers. Operating challenges are seen in all treatment steps for full field polymer injection implementation due to separation but also handling of the polymers in water treatment facilities.
Effects of Rock Anisotropy on Integrated Modelling
Authors: Li L. , Bakk A. , Fjær E. , Bauer A. , Stenebråten J.F. , Holt R.M. 
Published: May 2015

Abstract
Associated with reservoir monitoring towards optimizing production of oil and gas and maximizing the recovery, or ensuring safe CO2 storage, it may be beneficial to introduce integrated geomechanics, rock physics and seismic modelling in the work flow. The geomechanics modelling estimates the effective stress change and deformation in the reservoir and surrounding rocks induced by reservoir pore pressure change. The rock physics modelling estimates the subsequent change of the seismic wave velocities in the rock. Then the seismic modelling estimates detectable changes in the seismic signals. Rock anisotropy may affect every component in such integrated modelling. In this paper we performed the integrated modelling study and compared two simplified cases: In one case, all the rocks were assumed isotropic in stiffness, while in another case, the overburden and sideburden were assumed transeversely isotropic. The geomechanical modelling showed that the in situ stresses which were assumed pure results of rock gravity were already different in two cases. After reservoir depletion, the stress changes were different in two cases as well. A rock physics model was used to calculate the changes of seismic wave velocities as results of the changes of rock stresses and rock deformation. The rock physics model is based on the diffenrential effective medium theory and assumes the rock as a solid with spherical void inclusions and penny-shaped cracks, aiming at capturing stress-sensitive and anisotropic wave velocities. Seismic wave two way travel times and time shifts were calculated along different paths, with different offsets but the same reflection midpoint. The results show the difference between the isotropic case and the anisotropic case. Such difference increases with increasing offset. We conclude that such integrated modelling is important to understand the physical processes in the subsurface because those processes are interdependent. Rock anisotropy plays an important role in the physical processes and has significant impacts on the results of the integrated modelling.
Joint Interpretation of Interwell Connectivity by Integrating 4D Seismic with Injection and Production Fluctuations
Authors: Yin Zhen , MacBeth Colin , Chassagne Romain 
Published: May 2015

Abstract
A technique is proposed to quantitatively measure interwell connectivity by correlating multiple 4D seismic monitors to historical well production data. We make use of multiple 4D seismic surveys shot over the same reservoir to generate an array of 4D seismic differences. Then a causative relationship is defined between the 4D seismic signals and changes of reservoir fluid volumes caused by injection and production behavior. This allows us to correlate seismic data directly to well data to generate a “well2seis” volume. It is found that the distribution of the “well2seis” correlation attributes reveals key reservoir connectivity features, such as the seal of faults, inter-reservoir shale and fluid flow pathways between wells, and can therefore enhance our interpretation on interwell connectivity. Combining with conventional interwell methods that are based on injection and production rate variations, this multiple 4D seismic method is found to support the conventional interwell approaches and can provide more reliable and detailed interpretation.
Our methodology is tested on a synthetic model extracted from full-field data for a Norwegian Sea reservoir, the fluid flow of which is controlled by fault compartmentalization and inter-reservoir shale. The full structural details and reservoir properties are preserved but three scenarios with different degrees of reservoir connectivity are created. It is found that proposed technique successfully detects the flow paths of the injected fluids in all reservoir scenarios. A volumetric attribute is created that accurately identifies the distinctive types of key flow barriers and conduits for each scenario that are known to be major factors influencing the reservoir dynamics. This proves that the well2seis attribute agrees with geological interpretations better than conventional well connectivity factors based on engineering data only. Additionally, the combination of the two types of methods provides a more robust tool for characterization of the reservoir connectivity by providing both quantitative degree and physical pattern of interwell communication.
Integrated Model Based Decision Analysis in Twelve Steps Applied to Petroleum Fields Development and Management
Authors: Schiozer Denis José , Santos Antonio Alberto , Drumond Paulo Soares 
Published: May 2015

Abstract
This work describes a new methodology based on 12 steps for integrated decision analysis related to petroleum fields development and management considering reservoir simulation, risk analysis, history matching, uncertainty reduction techniques, representative models and selection of production strategy under uncertainty. The example of application is the field UNISIM-I-D which is a benchmark case based on Namorado field, Campos Basin, in Brazil. The main focus of the results is to show that the method can be used in practical applications, i.e., complex reservoirs in different field stages (development and management) because it allows the integration of static (geostatistical images generated by reservoir information) and dynamic data (well production and pressure) to reduce uncertainties allowing risk analysis integrating geological, economic and other uncertainties yielding a decision analysis based on risk-return techniques. In this methodology, no proxy model is used so reservoir simulation is used directly to reproduce field performance. We also show that the methodology is efficient and easy to use, even in complex cases where the computational time is an important concern and in real time operations.
Effects of Water Salinity, CO2 Solubility, and Gas Composition on Coal Wettability
Authors: Ibrahim Ahmed Farid , Nasr-El-Din Hisham A. 
Published: May 2015

Abstract
Geological sequestration of CO2 in coal seams has become an attractive carbon sequestration technology for two reasons. First, the injection of CO2 or mixtures of CO2 and N2 enhances methane production from coalbeds (ECBM). Second, it reduces the effect of global warming by storing CO2. The sequestration of CO2 in Tiffany and Allison fields in the San Juan Basin is an example of this technology. The efficiency of this process is strongly dependent on the wetting behavior of the coal–water–CO2 system and the CO2 diffusion rate from the cleat network, through the micro-cleats, and to the matrix surface, which is improved if the coal is CO2 wet.
This study aims to investigate the effects of the salt type and concentration of coal seam water, the solubility of CO2 in water, and the injected gas composition on the wettability of a highly volatile bitumen coal with 82 wt% carbon content from Bull Hill, Oklahoma. Contact angles in the coal–water–CO2 system were measured using a captive bubble method at pressures up to 1000 psi. Adsorption isotherm measurements were conducted to confirm the effect of salt concentration on the CO2/coal surface adsorption behavior. The zeta potential was measured to examine the effects of the salt concentration on coal hydrophobicity.
The results showed that the coal tended to be CO2 wet as the pressure increased where the contact angle changed from 80° at atmospheric pressure to 125° at high pressure (1000 psi). It was found that the salt concentration increased the coal wettability to the CO2. NaCl increased the contact angle values from 125° to 140° with a NaCl concentration of 15 g/L. It was found that MgCl2 and CaCl2 slightly increased the contact angles. These results were confirmed by measuring the adsorption isotherm and the zeta potential at different water salinities. The CO2 adsorption was improved as the salt concentration increased and the absolute zeta potential value decreased, especially in NaCl cases. It was found that the contact angles of flue gases were generally smaller than those of CO2 and the contact angles did not exceed 90° even at high pressures and high N2 contents (81° at 1000 psi for 100% N2). The solubility of CO2 in water did not affect the stabilized contact angle values but it minimize the stabilization time as the solubility increased.
Based on these observations, for CO2 storage and ECBM purposes, injection of CO2 into highly volatile bitumen coal seams is more efficient as the salt concentration content increase. However, other types of coals might show different behaviors due to their varying rank and mineral compositions.
A Study of the Interaction Mechanism between Hydraulic Fractures and Natural Fractures in the KS Tight Gas Reservoir
Authors: Zhang Fuxiang , Qiu Kaibin , Yang Xiangtong , Hao Jun , Yuan Xuefang , Burghardt Jeffrey , Liu Hongtao , Dong Jianyi , Luo Fang 
Published: May 2015

Abstract
The KS reservoir is a naturally fractured, deep, tight gas sandstone reservoir under high tectonic stress. Development wells for this reservoir are of depths in excess of 6,500 m TVD. Stimulation is required to provide production rates that sufficiently compensate for the high cost of drilling and completing wells to access this deep reservoir. Hydraulic fracture design and execution must be optimal to ensure economic production. To effectively stimulate a more than 200-m thick sandstone reservoir yielding consistently high performance, it is critical to understand the interaction between hydraulic fractures and natural fractures, as the natural fractures significantly affect the growth and geometry of hydraulic fractures.
To this end, a comprehensive study was conducted involving frac pressure analysis of previously stimulated wells, microseismic data analysis, hydraulic fracturing modeling by using a fracturing simulator that honors the natural fracture system, near-wellbore 4D geomechanical simulation of mechanical response of natural fractures during hydraulic fracturing, and large block hydraulic fracturing tests. This study reveals that existing natural fractures results in complexity of hydraulic fracture systems both in the near wellbore region and in the far field region. The complexity in the far field is largely controlled by the intersection angle (defined as the angle between the natural fracture strike and the maximum horizontal stress direction) given the large differential horizontal stress in this field.
Based on an understanding of the interaction mechanism, an optimization of the hydraulic fracturing strategy was implemented in KS field. Improvements were made in staging, perforation, diversion, and the pumping schedule, which increased the averaged production rate more than 50% compared with previously stimulated wells.
Use of Emulator and Canonical Correlation to Incorporate 4D Seismic Data in the Reduction of Uncertainty Process
Authors: Ferreira Carla J. , Davolio Alessandra , Schiozer Denis J. , Vernon Ian , Goldstein Michael 
Published: May 2015

Abstract
In petroleum engineering, simulation models are used in reservoir performance prediction and in the decision-making process. These models are complex systems, typically characterized by a vast number of input parameters. Typically, the physical state of the reservoir is highly uncertain and, thus, the appropriate parameters of the input choices are also highly uncertain. 4D seismic data can reduce significantly the uncertainty of the reservoir because it has a high area resolution, as opposed to the observed well rates and pressure. However, two main challenges are faced to calibrate the simulation model using 4D seismic data. The process can be time consuming because most models go through a series of iterations before being considered sufficiently accurate to give an adequate representation of the physical system. The consideration of 4D seismic data as an observed parameter in the form of maps would lead to an unfeasibly large number of variables to be matched. To overcome such issues, the construction of an emulator that represents the simulation model and the use of the canonical correlation technique to incorporate 4D seismic data can be used. The present study constructed a stochastic representation of the computer model called an emulator to quantify the reduction in the parameter input space. 4D seismic data was incorporated in the procedure through the canonical correlation technique. The water saturation map derived from seismic data was converted into seven canonical functions. Such functions represent the observable characteristics to be matched in the uncertainty reduction process. A high number of evaluations was necessary to identify the range of input parameters whose outputs matched the historical data (4D seismic data). The large number of evaluations justifies the use of an emulator and the reduction of uncertainties with areal characteristics shows that 4D seismic data was successfully incorporated. The emulator methodology represents a powerful tool in the analysis of complex physical problems such as history matching. The incorporation of 4D seismic data as an observable output to be matched leads to a difficult problem to be solved. However, the canonical correlation permitted a successful incorporation of such data into the problem.
Three dimensional numerical simulations for non-breaking solitary wave interacting with a group of slender vertical cylinders
Authors: Mo Weihua , Liu Philip L.-F. 
Published: May 2015

AbstractIn this paper we validate a numerical model for-structure interaction by comparing numerical results with laboratory data. The numerical model is based on the Navier-Stokes(N-S) equations for an incompressible fluid. The N-S equations are solved by two-step projection finite volume scheme and the free surface displacements are tracked by the slender vertical piles. Numerical results are compared with the laboratory data and very good agreement is observed for the time history of free surface displacement, fluid particle velocity and force. The agreement for dynamic pressure on the cylinder is less satisfactory, which is primarily caused by instrument errors.