bluuebunny/crossref_metadata_2025_split huggingface dataset:
Linking Reservoir Simulators with Fracture Simulators
Authors: Miranda Carlos , Soliman M. Y. , Settari A. , Krampol Radim 
Published: February 2011

Abstract
Reservoir simulation is currently used as the primary technique to simulate the behavior of almost all types of hydrocarbon reservoirs. Although several techniques have been developed to simulate the behavior of hydraulic fractures in reservoir simulators, a lack of accurate modeling of fracture geometry and fracture-fluid leakoff, as well as some other effects on hydraulic fractures (e.g., non-Darcy flow, dynamic fracture-conductivity behavior, stress-permeability dependence), is commonly observed in commercial-reservoir simulators.
A different approach is presented in this paper to fill the gap between reservoir simulators and hydraulic fracture simulators. Software capabilities have been developed to import propped-fracture geometry, proppant-area concentration, and fracture-fluid leakoff from commercial, grid-based fracture simulators, into a reservoir simulator with capabilities to model multiphase, non-Darcy flow inside the fracture. This includes the effects of long-term dynamic conductivity, stress-permeability dependence, and condensates banking, etc. This functionality permits better modeling of fracture-flow behavior and gives better insight into the cleanup and productivity of fractured wells, which will in-turn allow the user to design better fractures.
Barnett Shale (Mississippian), Fort Worth Basin, Texas: Regional Variations in Gas and Oil Production and Reservoir Properties
Authors: Tian Y. , Ayers W. B. 
Published: February 2011

Abstract
In 2007, the Barnett Shale in the Fort Worth basin of Texas produced 1.1 trillion cubic feet (Tcf) gas and ranked second in U.S gas production. Despite its importance, variations of reservoir properties and their effects on well performances have not been assessed. Therefore, we evaluated production statistics for the 5 Barnett production regions, and to assess controls on Barnett Shale production rates and fluid composition, we related production to completion method, reservoir interval completed, reservoir properties and geologic setting.
In all five production regions, horizontal wells produce approximately twice as much oil and gas as do vertical wells. First Year gas production of horizontal wells (P50) ranges from 30 to 350 MMcf. First Year oil production from horizontal wells ranges from 0 to 8,000 bbl. There are positive relations between the reservoir units perforated and production rates and volume, but there are no obvious monotonic relations between perforation interval thickness and Peak Monthly or First Year oil or gas production. After filtering the wells by the number of fracture and acid treatments, we did not observe any relationships between production and perforated interval thickness.
On the basis of petrophysical characteristics from 800 well logs, we divided the Barnett Shale into 4 reservoir units that are significant to engineering decisions and reservoir performance. The most productive wells are perforated in Reservoir Units 2, 3 and 4, inclusive. Reservoir Unit 1 is a shaly interval that has a hot gamma ray response and is rarely perforated. Reservoir Unit 2 is laminated, siliceous mudstone and marly carbonate zone. Reservoir Unit 3, the most commonly perforated Barnett reservoir unit, is composed of multiple, stacked, thin, upward coarsening sequences of brittle carbonate and siliceous units interbedded with ductile shales. Reservoir Unit 4, the upper Barnett Shale, is composed dominantly of shale interbedded with upward coarsening, laterally persistent carbonate and siliceous units, similar to Reservoir Unit 3.
This research should provide operators with a better understanding of Barnett Shale geologic and reservoir properties and assist with optimizing development strategies and gas recovery. The results may be applicable to other developing shale gas plays.
Microseismic Moment Tensors: A Path to Understanding Growth of Hydraulic Fractures
Authors: Baig Adam M. , Urbancic Ted , Prince Marc 
Published: February 2011

Abstract
Event locations and magnitudes are the first-order quantities of interest in reporting the observations of a microseismic monitoring program. From this, interpretations can be made from the geometry of the microseismic cloud as to the efficiency of the treatment and the appropriateness of various fracture-mechanical models. Moment tensors add another layer of understanding to these processes. The moment tensor of a microseismic event is a representation of the mechanism responsible for the observed radiation of seismic energy. The moment tensors can help understand the states of stress and strain induced by the treatment, as well as giving insights into the geometry of the fracture network. Additionally, as these moment tensors can identify volumetric change, we have the opportunity try to correlate these mechanisms with the injection parameters and obtain a glimpse into how and where the medium is responding to the treatment.
We present the results of a microseismic monitoring study where the moment tensors have been determined. This study involves recording microseismicity from multiple sensor arrays where a number of good quality events were recorded.
The higher-order moment tensor analysis of these data show how the fracture is growing with the treatment. The distribution of moment tensors usually falls along a trend line between the mechanisms characteristic of crack-opening to crack-closure type events. The distribution of these crack-opening and closing events though time and space, and in relation to the parameters of the injection treatment, suggest how that the fractures grow with crack-opening events at the tip. The closure events occur behind the opening events, both temporally and spatially, and indicate that there is a flow of injectant throughout the volume.
Based on these analyses, we suggest that moment tensor solutions for microseismic events can be used to calibrate models of hydraulic fractures and other injection programs. Exploitation of these data will add to the insight gained from microseismic monitoring.
Unconventional Resource Assessment of the Montney Formation in Alberta
Authors: Anderson S. D. , Rokosh C. D. , Beaton A. P. , Berhane M. , Pawlowicz J. 
Published: February 2011

Abstract
The ERCB/AGS has collected data 293 core samples from the Montney Formation in Alberta and run a series of geochemical and geological tests to characterise the formation for resource assessment. The goal of this talk is to discuss the regional distribution of the data and its significance to unconventional gas production in Alberta. The data will be used for an unconventional gas resource analysis of the Montney.
The geochemical and geological tests include adsorption isotherms, Rock Eval/TOC, organic petrography, vitrinite reflectance, XRD whole rock and clay mineralogy, SEM imaging, thin section analysis and imaging, porosimetry, permeametry, and pycnometry. We will present maps and graphs of adsorbed and free gas content, thermal maturity, TOC, net silt and shale, porosity feet, mineralogy and grain density variations. The work we do will help to bridge the Alberta Montney knowledge gap and possibly spur interest in the area.
This presentation will focus on the geochemical characteristics of the Montney Formation as they relate to resource assessment. A few of the key factors influencing shale gas resource assessment include TOC, thermal maturity and adsorbed gas content. Samples we have collected have shown TOC ranges from 0.06 to 3.64 wt percent (Figure 1) and vitrinite reflectance values between 0.31 and 2.45. Through mapping and graphing we will analyse these results and their distribution. In addition, we will compare the adsorbed gas content versus the free gas content. Lastly, log porosity varies with grain density. In the Montney, grain density varies with the amount of dolomitisation. Mineralogy-derived grain density calculations (Table 1) will be presented to show spatial and temporal distribution and hence porosity.
A Gas Production System From Methane Hydrate Layers by Hot Water Injection and BHP Control With Radial Horizontal Wells
Authors: Yamakawa T. , Ono S. , Iwamoto A. , Sugai Y. , Sasaki K. 
Published: February 2011

Abstract
A gas production system from methane hydrate (MH) sediment layers by combination method with hot water injection and bottom hole pressure control at production well using radial horizontal wells has been proposed.
Firstly, gas production characteristics by the depressurization method with bottom hole pressure control have been evaluated by numerical simulations of cylindrical homogeneous MH layer model. The cumulative production gas amount or MH recovery ratio were limited with the pressure reduction from MH equilibrium pressure, because the sediment pressure must be suppressed to keep mechanical stability of sediment layers under the sea bottom. Furthermore, effects of numerical bock modeling and averaging physical properties of MH layers have been discussed as those numerical simulation errors against the original deposit model show a safety side results to evaluate economic issues in gas amount and production rate.
By applying the present production system with combining hot water injection and bottom hole pressure control, the numerical simulation results showed that dissociated region including two wells filled with hot water, named as hot water chamber, is expanded outer ward from the area center of MH layer with continuous gas production. The simulations on gas production by injecting 85°C hot water into the MH layer with 1km× 1km and 20m in thickness by using four pairs of dual horizontal wells 500m in length were carried out. It was found that 2MPa pressure reduction from MH equilibrium pressure made the gas production 2.2 times compared with the case of hot water injection only without pressure reduction control.
A Novel Injection Well String Design to Accelerate CO2 Dissolution in Deep Saline Sequestration
Authors: Shafaei M. J. , Abedi J. , Hassanzedeh H. , Chen Z. 
Published: February 2011

Abstract
Geological storage of carbon dioxide (CO2) is one of the proposed strategies for mitigation of global warming. The CO2 injected into saline formations has less density than that of the resident formation brine. The injected mobile supercritical phase migrates upward and spreads under the sealing rock, due to its buoyancy. While CO2 is in the free mobile phase, there is always a risk of leakage through natural and artificial pathways. Once CO2 is dissolved into brine, it cannot migrate upwards other than by diffusion; and, it can then be retained with a minimal risk of leakage. Therefore, solubility trapping could enable more secure storage.
The objective of this study is the proposal of a CO2 injection well string to increase CO2 dissolution in brine and thereby reduce the risk of leakage of the injected CO2. The proposed well string configuration employs a tubing annulus system equipped with gas lift valves: The supercritical CO2 is injected through the annulus, and fresh brine is injected through the tubing. The designed flow rate of the injected CO2 through gas lift valves enhances dissolution of the CO2 into the injected brine.
A simplified single-phase mechanistic model is developed, and analytical solutions of the governing equations are obtained. Using the developed model, the dissolution of CO2 into brine is characterized by governing dimensionless numbers, such as the Peclet and Sherwood numbers. Scaling relations are presented and can be used to investigate the mixing performance under various operating conditions.
Integration and Technology Options for Implementing CO2 Capture and Storage in Oil Sands Operations
Authors: Ordorica-Garcia G. , Carbo M. , Nikoo M. , Bolea I. 
Published: February 2011

Abstract
The majority of the technology development for CO2 Capture and Storage (CCS) is driven by the electric utility industry, where the emphasis is on large centralized units for electric power generation with coal as the primary fuel. The implementation of CCS in oil sands operations has significant potential to provide meaningful carbon emissions reductions. This paper presents various concepts for integrating leading CO2 capture techniques to bitumen extraction and upgrading processes. The main carbon capture technologies are reviewed and their relative advantages and disadvantages for implementation in bitumen mining, thermal bitumen extraction, and upgrading are discussed, leading to a qualitative assessment of their suitability for each oil sands process.
Integrated Reservoir and Decision Modeling to Optimize Spacing in Unconventional Gas Reservoirs
Authors: Turkarslan G. , McVay D. A. , Bickel J. E. , Montiel L. V. , Ortiz R. R. 
Published: February 2011

Abstract
Despite our increased experience, unconventional gas plays remain risky. In the face of this risk, operators must balance the need to conserve capital and protect the environment by avoiding over drilling with the desire to maximize profitability by achieving the optimal well spacing as quickly as possible. Previous unconventional gas developments such as the Carthage Field (Cotton Valley) have implemented multiple infill drilling programs over several decades to optimize well spacing, with significant reduction in value (McKinney et al. 2002). However, in emerging plays such as the non-core Barnett Shale and the Fayetteville Shale, historical infill programs are not available to evaluate optimal spacing and we do not have the luxury of developing these fields over the next 30-40 years. Existing approaches for optimizing development, such as integrated reservoir simulation studies or statistical moving-window methods, can be either prohibitively time-consuming and expensive or they do not consider the uncertainty inherent in the assessment.
The objective of our work was to develop technology and tools to help operators determine optimal well spacing in highly uncertain and risky unconventional gas reservoirs as quickly as possible. To achieve the research objectives, we developed an integrated reservoir and decision modeling system that incorporates uncertainty. We used Monte Carlo simulation with a fast, approximate reservoir simulation model to match and predict production performance in unconventional gas reservoirs. Simulation results are then integrated with a Bayesian decision model that accounts for the risk facing operators. We applied these integrated tools to a hypothetical case based on data from Deep Basin (Gething) tight gas sands in Alberta, Canada, to determine optimal development strategies.
We anticipate that the tools and methodologies developed will be applicable in most shale and tight gas reservoirs. These tools should ultimately be able to help operators determine, for example, the combination of primary development strategy (well spacing and/or completion method) and testing (pilot downspacings and/or tests of other completion methods) that maximizes future profitability. The optimal design of such programs in unconventional reservoirs, where the risks are high, is likely to pay large dividends.
Improved Proppant Transport System for Slickwater Shale Fracturing
Authors: Kostenuk N. , Browne D. J. 
Published: February 2011

Abstract
The primary purpose of stimulating shale reservoirs is to extend drainage radius by connecting natural fractures, thus maximizing Stimulated Reservoir Volume (SRV). A conventional proppant transport system relies on the viscosity of the fracture fluid to suspend and transport the proppant further into the formation. With the development of unconventional plays, shale gas reservoirs are being treated with slick water type treatments that have inherent low fluid viscosity. Slick water shale fracturing uses proppant transportation that depends on turbulent flow, sand banking and/or bed transport. These result in the majority of the proppant being deposited on the bottom of the created fracture, close to the wellbore, leaving a large portion of the created fracture length unpropped.
In trying to improve proppant transportation, many have focused their efforts on either reducing proppant size or density, both of which will lower proppant settling rates according to Stoke's Law. However, using smaller proppant sizes or expensive but lower strength lightweight proppants can result in lower fracture conductivities.
This paper examines a new proppant transport method that significantly reduces proppant settling and proppant banking in slick water shale fracturing treatments. This unique technology is based on modifying the surface property of proppant on-the-fly, where micro-bubbles are formed on the surface and around each proppant grain. These micro-bubbles change the buoyancy of the proppant granules. The proppant can therefore be transported in slick water, traveling further distances into the formation without settling, independent of gel viscosity.
Presented experimental data in this study is supported through lab studies, which include conductivity cell, core flow and proppant pack testing. Several tests were performed to examine and illustrate the proppant transport properties of this technology under simulated field conditions. This study also includes reservoir modelling, comparing well productivity with proppant distribution from bed load transport with the new proppant transportation system.
Improving the Performance of Vapor Extraction of Heavy Oil and Bitumen Using the Warm VAPEX Process
Authors: Rezaei N. , Mohammadzadeh O. , Chatzis I. 
Published: February 2011

Abstract
The advantages of solvent-based enhanced oil recovery processes for production of heavy oil and bitumen have always been sacrificed with their low oil production rates and also high solvent costs. Attempts have been made to integrate the solvent and thermal processes to attain better recovery techniques in terms of improved oil production rate, oil quality, and material and energy requirements. In this paper, the process of warm VAPEX is introduced where the injected solvent is superheated. The temperature of solvent vapor (nC5), permeability of packed medium, and the viscosity of oil in place were considered as experimental factors. The VAPEX experiments were performed at 3 temperature levels (36, 43 and 50 °C) using Cold Lake bitumen and Lloydminster heavy oil at two permeability levels (220 and 830 Darcy). The performance of the warm VAPEX process was compared to that of the conventional VAPEX. The packed model was placed in an isothermal bath of circulating hot air to lower the heat loss to surrounding and also to avoid temperature variations of the environment between different trials. During the experiments, the live and dead oil production rates, solvent content analysis, asphaltene content analysis and also residual oil analysis were conducted. The production performance was enhanced, to some extent, when the solvent was allowed to condense, by lowering the temperature of the isothermal bath below the solvent dew point temperature. However, upon a moderate degree of superheating (i.e., the mid-level temperature of 43 °C), the bitumen production was substantially increased at both levels of permeability. The solvent content and solvent-to-oil ratio during the warm VAPEX process decreased with increasing the degree of superheat. Except for the warm VAPEX trial at bubble point temperature, the solvent-to-oil ratios were lower in the warm VAPEX, as compared to the baseline. The asphaltene content analysis showed insignificant deposition of asphaltene during the conventional VAPEX process in which condensation did not occur. On the other hand maximum asphaltene precipitation was achieved at the lowest temperature level (bubble point temperature). At a fixed level of permeability and initial oil viscosity, the residual oil saturation increased with the level of solvent superheating. Therefore, by applying optimal operating conditions, the oil production rate significantly increases while the solvent-to-oil ratio decreases as a result of decreased solubility of solvent in the bitumen. Both factors favor the economy of the VAPEX process. In-situ upgrading of the crude will also occur, which contributes to the improved quality of the produced oil.
Forecasting Tight Gas Well Production with a Material Balance Constraint
Authors: Morgan Michael 
Published: February 2011

Abstract
In SPE 133615, Nobakht et al. [1] introduced a simplified method of production forecasting for tight/shale gas wells which exhibit extended periods of linear flow. The method is simple as it relies principally on a plot of inverse rate versus square root time. In the present work, we extend this method by applying a material balance constraint that allows for changing reservoir pressure with depletion. We generate curves for a type well. These curves are normalized on the basis of the initial rate of the well. This work shows that wells from similar producing areas will all fit on the same "type curve".
The advantages of this forecasting method are: (1) It requires only the initial rate and an estimate of Original Gas in Place (OGIP), (2) The cumulative gas production can be calculated at any given time without the need to time-step forward and (3) it can be used as a field development planning tool, when combined with the economics of multistage hydraulic fracturing.
The Application of Solvent-Additive SAGD Processes in Reservoirs With Associated Basal Water
Authors: Peterson J. , Riva D. , Edmunds N. , Solanki S. 
Published: February 2011

Abstract
This paper describes the results of a simulation and optimization study on the application of a solvent-additive steam-assisted gravity drainage (SAGD) process to reservoirs with associated basal water. A review of related studies is provided, together with a discussion of the pros and cons of potential alkane solvents in basal water reservoirs. Economics and the impact of dynamic and ultimate retention are discussed.
A general conclusion drawn from literature is that optimal solvent application to SAGD in reservoirs will likely involve time variations in both rate and composition of the solvent. This is also the case for reservoirs with associated basal water. This results in an optimization problem that has a large number of dimensions, and is very nonlinear. Genetic algorithms, which mimic biological evolution, have been found to be extremely effective in addressing such problems.
A key product of this effort, optimized for a simple clastic reservoir with associated basal water, is presented. The study produced an operable process, which could be described as a new combination of pre-existing concepts. The process offers material improvements in thermal bitumen supply costs, as well as recovery factor. Major reductions in the physical steam/oil ratio (SOR), (and therefore) capital intensity, water use and carbon emissions, are indicated.