bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiwell Deconvolution for Shale Gas
Authors: Tung Yit , Virues Claudio , Cumming Jonathan , Gringarten Alain 
Published: April 2016

Abstract
In the last decade, single well deconvolution (von Schroeter et al., 2001) has become recognised as a powerful tool for reservoir characterization. Deconvolution transforms well test pressure data measured at varying rates into an equivalent unit rate single drawdown which has the same duration as the pressure history and can be analysed using conventional techniques to identify boundaries and assess connectivity between different compartments and layers. As its name suggests, single well convolution is only applicable when there is no interference from other wells. i.e. to exploration, appraisal and isolated production wells.
In 2013, a multiwell deconvolution algorithm was presented (Cumming et al., 2013) which enables deconvolution to be applied to groups of interfering wells. The algorithm yields a unit rate deconvolved derivative for every well, representing the well signature with interferences removed; and the interference derivatives between well pairs. An example of use with eight interfering North Sea oil wells was presented by Thornton et al. (2015).
This paper describes the application of the Cumming et al. multiwell deconvolution algorithm to eight wells in a multilayer shale gas reservoir. The main objective of the study was to verify the capability of the multiwell deconvolution algorithm to remove the effects of interference between horizontal wells and to assess the efficiency of the actual well spacing, which had been intended to avoid interferences. This study can have an impact on upcoming LNG projects in Canada and other countries which are evaluating LNG prospects.
An additional objective was to identify an optimal testing procedure to minimise uncertainties on the deconvolved derivatives. This was done by numerically simulating the behaviours of a number of interfering, multiply-fractured, horizontal wells (from 2 to 8) for various rate sequences. The impact of including non-interfering wells in the multiwell deconvolution was also investigated.
It was found that the accuracy of the multiwell deconvolution process was very much dependent on the rate sequence: producing and shutting in wells sequentially provides better results that having the same rate sequence on all the wells. In addition, to minimize errors on the derivatives, the start of interference effects should be evaluated correctly and non-interfering wells should be excluded from deconvolution. Both require a good understanding of the reservoir.
The Impact of Crude Oil Induced Wettability Alteration on Remaining Saturations of CO2 in Carbonates Reservoirs: A Core Flood Method
Authors: Al-Menhali Ali , Krevor Samuel 
Published: April 2016

Abstract
Oil is an essential commodity in modern economies but the magnitude of carbon emissions associated with its consumption is significantly increasing the challenges of climate change mitigations. Carbon storage is well recognized as an important technology for CO2 emissions reduction on industrial scales. Observations and modeling have shown that residual trapping of CO2 through capillary forces within the pore space of saline aquifers, characterized as water-wet, is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO2 migration within the reservoir. In contrast, most of the major CO2 storage projects in operation and under construction are in depleting oil reservoirs utilizing CO2 for enhanced oil recovery (EOR). Carbon utilization and storage has a significant energy and economic benefits and is considered as an important component in achieving the widespread commercial deployment of carbon storage technology. However, there are no observations characterizing the extent of capillary trapping of CO2 in mixed-wet carbonate systems, a characteristic of most conventional oil reservoirs in the world. In this work, residual trapping of supercritical CO2 is measured in water-wet and mixed-wet carbonate systems on the same rock sample before and after wetting alteration with crude oil. In particular, CO2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is observed directly. A reservoir condition core-flooding laboratory was used to make the measurements. The setup included high precision pumps, temperature control, stir reactor, the ability to recirculate fluids for weeks at a time and an X-ray computed tomography (CT) scanner. The wetted parts of the flow-loop were made of anti-corrosive material that can handle co-circulation of CO2 and brine at reservoir conditions. The measurements were made while maintaining chemical equilibrium between the fluids (CO2 and brine) and rock phases to prevent reaction with the core sample and replicate conditions far away from the injection site. A novel core-flooding approach was used, making use of the capillary end effect to create a large range in initial CO2 saturation in a single core-flood.
Laboratory Review of Effect of Salinity on CO2 Storage Potential in Farnsworth Field
Authors: Ennin Edward , Grigg Reid B. , Petmecky Christopher 
Published: April 2016

Abstract
Understanding fluid/fluid and rock/fluid interactions in a reservoir are required to evaluate CO2 storage potential and safety. This paper examines the effect of salinity of reservoir brine on CO2 storage and the level of salinity best for CO2 storage. Relative permeability imbibition and drainage curves were generated to further understand the interaction between CO2 and brine in a reservoir.
A core flooding set up was built to replicate reservoir conditions of the Farnsworth Unit (FWU) in Texas, USA. The research involved three reservoir pay zone rocks obtained from depths of about 7687ft that were pieced together to undergo core flooding at 4400psi and a temperature of 168°F. During the 6 tests conducted the core was flooded with supercritical CO2 and brine of salinities 3000ppm, 6000ppm and 35000ppm to generate relative permeability curves to represent imbibition and drainage. Imbibition and drainage relative permeability curves are generated from the co-injection of CO2 and brine of varying salinity at different ratios and volumes.
After analyses of the imbibition and drainage relative permeability curves for the different salinities it is seen that the relative permeability curves looked very similar, in that all three relative permeability curves looked the same for imbibition tests and also for all the drainage tests regardless of the brine salinity. The volume of CO2 stored in the core was almost the same for the six different tests. From this research it can be concluded that CO2 storage, at least for these particular reservoir rocks, is not affected significantly by the salinity of the formation brine. It appears that the interaction between supercritical CO2 and different salinities of brine is not substantially different for the same rock sample.
Calibrating Multi-Point Geostatistical Models Using Pressure Transient Data
Authors: Hamdi Hamidreza , Sousa Mario Costa 
Published: April 2016

Abstract
Transient well test data conveys significant information about the subsurface heterogeneities in terms of some variations in the well test pressure response curves. It is therefore important to enhance the use of the well test data for building a validated geological model to include the effective reservoir heterogeneities that are reflected on the well test plots. In this work, we present a novel geoengineering workflow for geologically consistent updating of the geostatistical facies models using pressure transient data.
We use Multi-Point Statistical (or Geostatistical) simulations (MPS) with conditioning hard and soft data to generate the geostatistical realizations that can preserve the spatial connectivity of the facies. Static model transient tests are then generated using high resolution numerical simulations. The results are compared with the measured well test data for an inversion. The inversion step involves a geologically consistent Probability Perturbation Method (PPM) for perturbing the geostatistical models which are combined with a Gaussian Process (GP) modeling approach for finding the optimum spatial distribution of the facies and the other unknown model parameters. Conditional two-dimensional models of a low-energy anastomosing channelized model are considered in this study. The results show that using such an approach the spatial variation of the facies is maintained and the transitions across the facies boundaries are consistently preserved. In this paper, the geostatistical models are updated simultaneously with other unknown model parameters, including the PPM's parameter (r), facies permeabilities and the non-Darcy D-factor. This multidimensional inversion is efficiently performed by GP in less than 100 compositional simulations. The novelty of this work is to efficiently use the well test data for updating the static models in a fluvial reservoir using a perturbation of the geological models. Moreover, for the first time, a novel optimization method is combined with PPM to consistently update the model parameters with a limited reservoir simulation budget.
Insight of HASD Technology in an Extra Heavy Oil Field in Comparison to Traditional Thermal EOR Processes
Authors: Perez S. , Escobar E. 
Published: April 2016

Abstract
HASD (Horizontal Alternating Steam Drive) is a thermal EOR (Enhanced Oil Recovery) process with a mechanism based on the combination of horizontal Steam Flooding (SF) and Cyclic Steam Stimulation (CSS).
This paper presents the potential of HASD to exploit the reserves of one extra heavy oil giant field, located in the Orinoco Oil Belt (OOB), identifying the characteristics and quality of reservoir that are more suitable to use HASD in comparison to traditional EOR technologies based on steam injection, for the typical well configuration schemes used in the OOB, which is based on set of clusters of long horizontal wells.
The field object in the study requires, after an initial stage of cold production, the application of an EOR process to meet the target production plateau of the field development plan. The thermal EOR technologies based on steam injection are the ones more suitable to be applicable in this field, as it was established by a detailed EOR prescreening study, previously performed for this field.
The evaluation of the oil recovery of this giant field is based on a sectoring strategy, considering that the size of the field makes unfeasible a full field reservoir simulation using a thermal EOR process. Considering the different thicknesses and heterogeneities found in the field, the identification of a proper number and type of sectors is required to be able to represent adequately the different reservoir qualities.
The performance of different thermal EOR processes has been evaluated using numerical simulation in all of the sectors selected for the field. The operating conditions of each technology were obtained after carrying out an optimization study based on different reservoir qualities. The detailed analysis of production behavior in the different reservoir quality sectors for an optimized set of operating conditions allows understanding the applicability and potential of the different thermal oil recovery processes in diverse parts of the field.
This paper presents the results from the assessment made on three different sectors of the field, each one characteristic of a specific reservoir quality, to evaluate the potential application of the HASD technology. A comparison with the performance of CSS and SF on the same sectors is presented and the type of reservoir quality more adequate for HASD is identified, together with a recommended set of operating conditions.
HASD process has not any commercial reference up to this moment; the results presented in this study can support the decision to consider the definition of a pilot project that paves the way to the first commercial application of HASD.
Investigation of CO2 Enhanced Gas Recovery in Shale Plays
Authors: Zhang Kai , Liu Qingquan , Wang Min , Kong Bing , Lv Jiateng , Wu Keliu , Chen Shengnan , Chen Zhangxin 
Published: April 2016

Abstract
Shale gas production gets a tremendous breakthrough with the advent of horizontal well and massive hydraulic fracturing. There is still extensive gas stored in a reservoir after primary production so gas injection has a possibility to improve gas recovery for a shale play. In shale gas reservoirs, the gas can be in a free or absorbed state. In addition, there is a difference in the adsorption capacity between hydrocarbon and non-hydrocarbon components, therefore, it may cause gas recovery variation by hydrocarbon and non-hydrocarbon gas injection.
In this paper, a Montney shale gas reservoir is modeled by Petrel based on data from Accumap. CH4/CO2 flooding performances are simulated by CMG GEM. Results have shown that CO2 has a good potential of gas production improvement in shale gas reservoirs. Furthermore, the higher the total organic content (TOC) of a shale reservoir, the better CO2 enhanced gas recovery (EGR) performance.
Modeling of Foamy-Oil Flow in Solvent-Based Recovery Processes
Authors: Jia Xinfeng , Li Jianli , Chen Zhangxing , Gu Yongan , Zeng Fanhua 
Published: April 2016

Abstract
Solvent-based recovery processes, such as cyclic solvent injection and its variants, have shown a great potential to enhance heavy oil recovery after cold heavy oil production with sands. In such processes, pressure is increased and reduced in a cyclic manner to induce foamy oil flow, which is a key production mechanism. Previous conclusions of foamy oil flow in primary production may have limitations for cyclic processes since the fluid properties and operating conditions are fairly different. This study first conducted an experimental study to visualize the foamy oil flow in a scaled physical model under realistic reservoir conditions. Pseudo-bubble points at different stages of the test are recorded. Then a mathematical model is developed to simulate the experimental observations. This model reasonably couples pressure diffusion and mass transfer together, and considers dynamic properties of gas, foamy oil and diluted oil. Experimental observations show that the oil zone remains relatively stable before pressure drops to a certain level. Afterwards, the oil front moves explosively inwards the solvent chamber, indicating a flow of foamy oil. Theoretical modeling results show that the pressure gradient at the oil-gas zone interface increases from zero at the beginning to a considerable value during a drawdown process. The foamy oil flows only when the pressure gradient reaches a certain level, and a larger drawdown rate tends to result in a higher pressure gradient and a higher pseudo-bubble point. In addition, at the same pressure drawdown rate, the foamy oil flow at a later stage is expected to happen more quickly than at an earlier stage.
Quantitative Assessments of CO2 Injection Risks for Onshore Large Scale CO2 Storage
Authors: Le Gallo Yann , Carballo Taimara Acosta 
Published: April 2016

Abstract
Within the European context, CO2 storage operations shall address the potential impacts of large scale CO2 storage through risk assessment. The key risks identified for this onshore CO2 storage site were the migration through faults and ground deformation.
To quantify the CO2 migration along a fault, flow modelling and uncertainties management codes are coupled to compute the failure probability i.e. the probability of CO2 migration towards a control aquifer. Such probability of failure is characterized by low to very low probability of occurrence which requires a large number of simulations to enable its evaluation. Each failure scenario models the CO2 migration from a storage aquifer to a control aquifer when altering the flow properties of the fault zone. Fault failure analyses are performed on the surrogate models. They show that limited CO2 migration is occurring along the fault but no breakthrough in the control aquifer. The injection induces some pressure disturbance in the control aquifer in about 30% of the cases which lead to effective stress changes.
To quantify effective stress changes due to CO2 injection and the subsequent ground deformation, the mechanical responses of the different sediment layers are modeled coupling flow and geomechanics. The impact of the stress changes on porosity and permeability of the storage reservoir is modeled along with the impact of uncertainties of the mechanical parameters. For this onshore CO2 storage site study case, the expected ground displacement is negligible (below the limit of the measurement capabilities).
3D Geomechanical Modeling and Fault Reactivation Risk Analysis for a Well at Brage Oilfield, Norway
Authors: Serajian V. , Diessl J. , Bruno M. S. , Hermansson L. C. , Hatland J. , Risanger M. , Torsvik M. 
Published: April 2016

Abstract
The objective is to investigate potential fault reactivation caused by high-volume injection into a North Sea well to assess the risks associated with converting a production well into a water injection well. The well is located within the Brage Field less than 100 meters from a major fault and there is concern for fault reactivation due to high volume water injection near this fault.
An integrated 3D geologic, fluid flow and geomechanical model was developed for the area of interest to evaluate fault reactivation risks. The 3D integrated models were constructed based on seismic horizon data and well logs. The 3D fluid flow model was calibrated and history matched using the pressure and temperature data from the current well and other adjacent wells. The developed 3D fluid and heat flow model was used to estimate pressure and temperature distributions adjacent to the fault after water injection in the target well. The results of the 3D fluid flow model were then imported into the 3D geomechanical model to predict the induced stresses and displacements near the injection zone and on the face of the fault.
The results of the integrated geologic, fluid flow and geomechanical models indicate that the poro-elastic stresses induced by high volume injection into the proposed well are not sufficient to induce major slip on the nearby main fault, considering a wide range of reasonable physical and material property assumptions for the fault.
The results of this study are used in specifying the maximum daily water injection rates in the proposed well without the fault reactivation concerns. With the proposed water injection rate, the sealing capacity of the major fault will be guaranteed and the injected water will be directed into the reservoir for pressurization and water flooding purposes.
Forage Harvest Timing Impact on Biomass Quality from Native Warm‐Season Grass Mixtures
Authors: McIntosh David W. , Bates Gary E. , Keyser Patrick D. , Allen Fred L. , Harper Craig A. , Waller John C. , Birckhead Jessie L. , Backus William M. 
Published: April 2016

Core Ideas

Use mixed species native warm‐season grasses for forage/biomass production.
Provide nutritional and quality data on switchgrass and mixed species stands for forage and ethanol production.
It is possible to alter forage nutritive values/biomass quality with the addition of other grasses with switchgrass.
Biomass production systems using native warm‐season grasses can allow for an early‐season harvest (for forage) followed by a dormant harvest (for biomass). A study was conducted to investigate the impact of harvest timing and grass species on the chemical composition of harvested forage and biomass. The three‐species composite treatments were switchgrass (SG) (Panicum virgatum L.); a two‐way blend of big bluestem (Andropogon gerardii V.) (BB) and indiangrass (Sorghastrum nutans L.) (IG); and a three‐way mixture of SG, BB, and IG. Harvest treatments were a biomass harvest (BH) in late fall, early‐boot (EB) harvest (for forage) followed by BH, or early‐seedhead harvest (ESH) (for forage) followed by BH. Forage harvested at EB had greater crude protein and less neutral detergent fiber (NDF) and acid detergent fiber (ADF) compared with ESH (P = 0.05). The ADF and NDF content of biomass was greatest for BH and was reduced in biomass regrowth after EB, with the later ESH resulting in the largest decrease in fiber content. Total macronutrient removal of N, P, and K was increased in the dual‐use system. Results indicated that it is possible to alter the composition of biomass provided for bioenergy production by taking an early‐season forage harvest.
Improved Simulation of Edaphic and Manure Phosphorus Loss in SWAT
Authors: Collick Amy S. , Veith Tamie L. , Fuka Daniel R. , Kleinman Peter J.A. , Buda Anthony R. , Weld Jennifer L. , Bryant Ray B. , Vadas Peter A. , White Mike J. , Harmel R. Daren , Easton Zachary M. 
Published: April 2016

Watershed models such as the Soil Water Assessment Tool (SWAT) and the Agricultural Policy Environmental EXtender (APEX) are widely used to assess the fate and transport of agricultural nutrient management practices on soluble and particulate phosphorus (P) loss in runoff. Soil P‐cycling routines used in SWAT2012 revision 586, however, do not simulate the short‐term effects of applying a concentrated source of soluble P, such as manure, to the soil surface where it is most vulnerable to runoff. We added a new set of soil P routines to SWAT2012 revision 586 to simulate surface‐applied manure at field and subwatershed scales within Mahantango Creek watershed in south‐central Pennsylvania. We corroborated the new P routines and standard P routines in two versions of SWAT (conventional SWAT, and a topographically driven variation called TopoSWAT) for a total of four modeling “treatments”. All modeling treatments included 5 yr of measured data under field‐specific, historical management information. Short‐term “wash off” processes resulting from precipitation immediately following surface application of manures were captured with the new P routine whereas the standard routines resulted in losses regardless of manure application. The new routines improved sensitivity to key factors in nutrient management (i.e., timing, rate, method, and form of P application). Only the new P routines indicated decreases in soluble P losses for dairy manure applications at 1, 5, and 10 d before a storm event. The new P routines also resulted in more variable P losses when applying manure versus commercial fertilizer and represented increases in total P losses, as compared with standard P routines, with rate increases in dairy manure application (56,000 to 84,000 L ha−1). The new P routines exhibited greater than 50% variation among proportions of organic, particulate, and soluble P corresponding to spreading method. In contrast, proportions of P forms under the standard P routines varied less than 20%. Results suggest similar revisions to other agroecosystem watershed models would be appropriate.Core Ideas
Dynamic manure P routines were added to the conventional SWAT model.
New P routines were corroborated in two versions of SWAT.
New P routines accurately simulated the 4R effects of manure management.