bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dual Porosity Typecurves for Shale Gas Reservoirs
Authors: Moghadam S. , Mattar L. , Pooladi-Darvish M. 
Published: February 2011

Abstract
Recent advances in the analysis of production data suggest that in shale reservoirs, a horizontal well with multiple hydraulic fractures creates a Stimulated Reservoir Volume (SRV). This SRV consists of matrix and fissures similar to a naturally-fractured system. Traditionally, dual porosity reservoir models have been used to describe the behavior of naturally-fractured reservoirs, and therefore these models can also be used to analyze the gas production from the SRV of shale reservoirs.
Often linear flow is the dominant flow regime in these reservoirs, and because of the low permeability, production takes place at high drawdowns (effectively constant wellbore flowing pressure). Accordingly, in this work, we develop typecurves for linear flow, constant flowing pressure, and transient dual porosity. First, we identify the different types of linear flow that may be seen in transient matrix-to-fissure interporosity flow, in the presence of a fully penetrating hydraulic fracture. Second, we provide practical criteria to differentiate between the types of linear flow. This allows us to determine if the reservoir can be treated as an equivalent homogeneous reservoir or if it should be treated as a dual porosity system.
In the paper, we generate dual porosity typecurves for various Lambda and Omega values, and convert them to a single curve that is equivalent to Wattenbarger's linear flow typecurve. We propose a work flow using this single curve, and we identify if and when it is possible to uniquely evaluate reservoir properties such as effective permeability and areal extent of the fissured system (SRV).
Effects of Nano Sized Metals on Viscosity Reduction of Heavy Oil/Bitumen During Thermal Applications
Authors: Hamedi Shokrlu Y. , Babadagli T. 
Published: February 2011

Abstract
Conventional (steam injection) and unconventional (electrical/electromagnetic heating) heavy oil/bitumen recovery methods require a high amount of energy. The efficiency of these methods can be increased by improving the energy transfer to the oil for viscosity reduction. It has recently been shown that micron-sized metal particles improve the efficiency of some ex-situ processes such as coal liquefaction and pyrolysis, heavy oil upgrading, oil shale recovery, and heavy oil viscosity reduction. This idea, with some modifications, can be applied to reduce the energy input of the aforementioned recovery methods for more economical heavy oil/bitumen production. The major contribution of the metal particles is expected to improve viscosity reduction by reducing the amount of the required energy. The objective of this work is to clarify the mechanics of additional viscosity reduction using nano-size metals during thermal applications through a series of experiments.
In the absence of electromagnetic fields, exothermic chemical reactions and thermal conductivity enhancement are the two important functions of metals to cause a reduction of oil viscosity. Two sets of experiments were conducted to investigate these mechanisms. Different metal types including iron, nickel and copper with different sizes and their different compounds were selected. The viscosity of oil samples, mixed with these particles, was measured. The tests were repeated at different temperatures. Also, the effect of the metal particles on heat transfer enhancement was examined. Nano-sized particles were found to have a remarkable effect on heat transfer through heavy oil.
The experiments provided a good understanding of the ongoing mechanisms that would lead to a viscosity reduction by the addition of metal particles. The concentration, type, and size of the particles were found to be highly critical on viscosity reduction. The optimal values of these parameters were identified. The results and observations are expected to be useful in further studies and applications as to the efficiency improvement of the thermal applications for heavy-oil/bitumen recovery.
Optimal Amount of Solvent in Solvent Aided Process
Authors: Gupta S. , Gittins S. , Sood A. , Zeidani K. 
Published: February 2011

Abstract
The Solvent Aided Process (SAP), described previously in literature, is an improvement to SAGD that promises to enhance the economics of bitumen/heavy oil recovery projects and reduce their impact on the environment. In SAP, a small amount of hydrocarbon solvent (such as a low molecular weight alkane) is introduced as an additive to the injected steam during SAGD. The viscosity of the oil thus is reduced due to solvent dilution in addition to heating. SAP can significantly improve the energy efficiency of SAGD, thus reducing the heat requirement. Cenovus's field trials of SAP, discussed elsewhere, have shown the practical upside of this process. Modeling predicts that the higher the amount of solvent used in SAP, the better is the performance (rates, energy intensity) of the recovery process. Besides rate of Bitumen production, economics of SAP depend on the availability and cost of solvent. Although the existing literature has discussed deterministic variations in solvent input, it is largely silent on how much solvent is the right amount of solvent in SAP.
This paper contains discussion of using optimal amount of solvent with steam in SAP. The discussion is based on modeling and compares performance of the scheme under various solvent injection strategies. It explores effect of temporal variation in the concentration of solvent at the vapor-liquid interface as well as of pulsed solvent injection on the performance of the process.
Cyclic Steam Injection With Solvents as Method of Thermal Recovery for Heavy and Extraheavy Oils: Laboratory Tests
Authors: Castro Y. E. , Veliz A. M. , Sanchez D. A. , Rodriguez M. M. , Rondon N. G. , Rivero S. , Cortez M. L. 
Published: February 2011

Abstract
Venezuela has the biggest reserves of heavy and extra heavy oils in the world. High viscosity of heavy and extra heavy oils is the main difficulty for its exploitation and production. Steam injection is a possible enhanced oil recovery (EOR) technique most widely applied to this type of oils based on temporary viscosity decrease. Commonly, it is used in Venezuela and Canada; however, factors as steam availability at field operations and low values of displacement efficiency achieved along the process by oil viscous forces have affected its possible use in the future.
Nowadays, PDVSA Intevep is evaluating the potential application of the method using some light oil cuts as solvents or additives which are from refineries located nearly to the fields under exploitation operations.
So far, static tests have been carried out by using methane, heavy oil from a Venezuelan field (9°API y 41500cP@43 °C) and solvents as light oil cuts (naphtha, kerosene) and two types of effluents from some refinery processes which will be named cut A and B along this investigation at saturated steam conditions. Displacement tests using displacement cells at reservoir conditions in porous media (253 °C, 400 psi, 30% porosity value and 4 Darcies, permeability) have also been performed in order to determine percentages of oil recovery.
Results indicated no net differences between the solvents selected during oil - solvent compatibility tests. Nevertheless, the effluents named 1 and 2 increased percentages of recovery factor notably along displacement tests obtaining values around 50 % in comparison to conventional displacement tests by using steam only. Hence, the use of this type of effluents which are cheaper than the light oil cuts selected is being recommended as potential application at field operations in Venezuela taking into account further studies as well as further technical and economical evaluations.
SWACO2 and WACO2 Efficiency Improvement in Carbonate Cores by Lowering Water Salinity
Authors: Aleidan A. , Mamora D. D. 
Published: February 2011

Abstract
We have performed a miscible CO2 flood study using heterogeneous carbonate cores and 31°API west Texas oil to evaluate oil recovery under four injection modes: simultaneous water and CO2 (SWACO2), water alternating CO2 (WACO2), continuous gas injection (CGI), and waterflood (WF). For WACO2 and SWACO2 injection modes, three salt concentrations are used: 0, 6, and 20 wt. %. For WF, two salt concentrations are used: 0 and 6 wt. %.
The experimental results may be summarized as follows: For injected water with 20 wt. % salt concentration, the oil recoveries for SWACO2 and WACO2 are 81 and 74 % oil initially-in-place (OIIP), respectively. For 6 wt. % salt concentration, the oil recoveries for SWACO2 and WACO2 increased to 90 and 86.5% oil initially-in-place (OIIP), respectively. With injected pure water (0 wt. %), the oil recoveries for SWACO2 and WACO2 increased to 98 and 92 % OIIP, respectively. The waterflood oil recovery remains the same at 54% for both salinity levels indicating that dissolved CO2 is the critical factor in oil displacement. Literature data suggests that CO2 solubility in water increases when salinity of the injected water is reduced. The low salinity water with CO2 appears to increase the microscopic oil displacement efficiency.
Evaluation of the Potential of Microbial Conversion Process of CO2 Into CH4 by Investigating the Microorganisms in High CO2 Content Oilfield
Authors: Sugai Y. , Purwasena I. A. , Sasaki K. , Fujiwara K. 
Published: February 2011

Abstract
CO2 sequestration into depleted oil reservoirs has been expected to be a method of reducing CO2 emission. We focus on the in-situ conversion of CO2 into CH4 by hydrogenotrophic methanogens which inhabit oil reservoirs universally. This conversion process has not only the potential of reducing CO2 emission but also the potential of reproducing natural gas deposit in reservoirs. The hydrogenotrophic methanogens need not only CO2 but also H2 to produce CH4, therefore, H2 should be supplied to them in reservoirs for this process. It has been reported there are several kinds of bacteria which produce H2 by degrading parts of crude oil in reservoirs. In this study, the potential of this conversion process was evaluated by investigating the habitation of these bacteria in a high CO2 content oilfield. Reservoir brine samples were extracted in a high CO2 content oilfield. Concentration of CO2 and CH4 in the gases which were produced from reservoirs in the oilfield was 35–60% and 20–40% respectively. Microbial genomic DNAs were extracted from reservoir brine and their nucleotide sequences were analyzed to identify the species inhabiting the brine. Thermotoga naphthophila and Thermoanaerobacter sp. which are well known as oil-degrading and hydrogen-producing bacteria were detected as a dominant in the brine. Moreover, Methanobacterium sp. and Methermicoccus sp. which are well known as hydrogenotrophic methanogens were also detected in the brine. It is assumed that these hydrogenotrophic methanogens live in symbiosis with oil-degrading and hydrogen-producing bacteria and convert CO2 into CH4 in the reservoirs. In addition, culture experiments of the microorganisms which belonged same genus or same family of the above microorganisms were carried out under the reservoir conditions. Both hydrogen production and methane production were observed in the experiments. These results indicate that the in-situ microbial conversion process of CO2 into CH4 has high potential.
Energy Efficiency in the Electrical Heating of Methane Hydrate Reservoirs
Authors: Callarotti R. C. 
Published: February 2011

Abstract
In this paper we analyze the production of methane gas from methane hydrate deposits when heat is supplied by an electrical heater located in the reservoir. The reservoir is assumed to have cylindrical symmetry of variable external radius and variable thickness. By means of the enthalpy method we determine numerically the transient response of this system under a constant applied electrical power supplied to a cylindrical heater located at the center of the reservoir and at different depths. We determine the volume of methane hydrate that will melt and the energy equivalent of the gas thus produced. The energy efficiency of the heating process is obtained as the ratio of the gas equivalent energy to the applied energy.
In the calculations the heater temperature is maintained constant by a down-hole controller, so as to avoid the conversion into steam of the water produced. For different levels of applied electrical power, at a given heater temperature, we find that there is an optimal value of heater length where the ratio of the equivalent energy produced to the energy input is a maximum.
The energy efficiency of this heating process is the critical factor in determining the feasibility of an electrical heating production scheme.
Assessment of the Distribution of Technically-Recoverable Resources in North American Basins
Authors: Cheng K. , Wu W. , Holditch S. A. , Ayers W. B. , McVay D. A. 
Published: February 2011

Abstract
As gas production from conventional gas reservoirs in the United States decreases, the industry is turning more to the exploration and development of unconventional gas resources (UGR), especially shale gas reservoirs. This trend is expanding quickly worldwide. Unlike in many mature North American basins, where resources and reserves are well characterized, the volume of unconventional gas resources is generally unknown in most basins outside North America (frontier basins). Therefore, a comprehensive investigation and evaluation of North American unconventional gas resources is significant not only for identifying and understanding the quantitative distributions of recoverable UGR in North American basins, but also for estimating the volume of UGR in frontier basins. Our investigation of North American unconventional gas resources is based on the resource triangle concept, which implies that all natural resources, including oil and gas, are distributed lognormally in nature. Martin et al. (2010) described a methodology to estimate values of total recoverable resources (TRR) for unconventional gas reservoirs. In their work, the authors combined estimates of production, reserves, reserves growth, and undiscovered resources from a variety of sources into a logical distribution. They used data from 8 basins in North America to demonstrate their results. We have expanded the work of Martin et al. (2010) to include data from a total of 25 basins in North America. The results show that the overall ratio of TRR in unconventional gas reservoirs to those in conventional oil and gas reservoirs in the 25 basins is approximately 4 to 1. This means that for every Tcfe of oil and gas produced from conventional reservoirs, one could expect another 4 Tcfe to be technically recoverable from unconventional gas reservoirs in the same basin. This observation can help companies assess the potential of unconventional gas resources development in North American basins and in frontier basins worldwide.
A Simulation Study of a Cyclic Steam Stimulation Pilot in a Deep Carbonate Heavy Oil Reservoir in Oudeh Field, Syria
Authors: Li M. , Astete E. , Wang H. 
Published: February 2011

Abstract
The Oudeh Shiranish reservoir in Syria contains 5.1 billion bbls of 12-16 °API crude oil. However primary recovery factor is estimated to be only 5 to 7% of the original oil in place. To increase oil recovery, waterflood, VAPEX, microbial treatment and cyclic steam stimulation (CSS) were examined. Eventually, CSS was selected for a pilot test despite the depth of the reservoir, approximately 1600 meters, was deeper than most successful CSS projects in the world.
The CSS pilot was implemented in September 2006 and suspended in November 2009. The project expanded from 2 to 24 wells. Low steam quality at the bottom of the well proved to be the most prominent challenge due to a combination of heat loss in the wellbore and relatively low steam injectivity. Only hot water reached the bottomhole when steam was injected through casing. Injection into tubing improved steam quality. Vacuum insulated tubing (VIT) produced the best, increasing steam quality to between 20 and 40% at a wellhead steam quality of 80% and an injection rate of 200 m3 CWE/day. The high pressure required to inject into the Shiranish reservoir at close to or higher than initial reservoir pressure conditions means that the latent heat of vaporization is low, compared to the typical CSS injection pressure, resulting in a less effective heating process.
In the study, a new thermal simulation model was developed to examine history-matching parameters, match the well and pad performances and optimize operations if the pilot were to be continued. Excellent history matches were achieved. Forecast indicated that Shiranish CSS performance was positive and could increase oil recovery by up to 100% over cold production.
Analytical Solution for Gas Production from Tilted Gas Hydrate Reservoir
Authors: Hamed Tabatabaie S. , Pooladi-Darvish M. 
Published: February 2011

Abstract
The declining conventional hydrocarbon resource and increase in energy demand has encouraged the development of unconventional gas resources. One specific type of unconventional gas is the natural gas hydrate. The substantial size of the hydrate resource is a motivating factor in its development. In the early phases of development of hydrate reservoirs data is limited and a large number of sensitivity studies are required. Efficient and accurate analytical models are suitable for such sensitivity studies. One of such solutions is presented in this work.
An analytical solution is developed to model rate of gas generation and hydrate recovery when gas is produced from an inclined hydrate-capped gas reservoir where the geothermal gradient is accounted for. As a result of the difference in temperature within the hydrate column, the size of the decomposing area increases with continued production.
Development of the analytical model of this work is based on a material balance equation that is combined with the solution for the temperature of the decomposed zone and hydrate equilibrium curve. The three equations are solved simultaneously for the gas generation rate. To validate the assumptions made in the development of the analytical model, a numerical simulator was used. The effects of different reservoir parameters on the reservoir performance were investigated by performing sensitivity analysis. The sensitivity results show how a steeper reservoir that extends closer to the base of permafrost leads to less recovery, or how a thicker hydrate cap could maintain the reservoir pressure for a longer time.
The model developed in this study can be used as an approximate engineering tool to evaluate the role of hydrates in improving the productivity and extending the life of tilted hydrate-capped gas reservoirs.
Integrated Assessment of CO2-Enhanced Oil Recovery and Storage Capacity
Authors: Zhang Y. , Zhang L. , Niu B. , Ren S. 
Published: February 2011

Abstract
CO2 enhanced oil recovery (EOR) has been used as a commercial process for enhancing oil recovery since the 1970s, whereas limited field applications of CO2 storage were undertaken only recently. In practice, considerable reservoir engineering design effort was made to reduce the total amount of CO2 required to recover each barrel of oil in a CO2 EOR project. For CO2 storage, however, the objective is to increase the amount of CO2 left behind at the end of the injection process; therefore, the approach to the design question changes. Consequently, optimization of CO2 EOR and CO2 storage processes differs significantly from the current CO2 injection practices. In this paper, techniques were developed to systematically assess CO2 EOR and storage capacity in a hydrocarbon reservoir selected for a demonstration project. More specifically, oil recovery was assessed and determined under miscible conditions, while CO2 storage capacity was determined by using an estimation model improved in this study. In addition, economic analysis was conducted, assuming that CO2 was captured from a chemical plant and transported 120 km to the oilfield. It is found that the geological framework is suitable for CO2 storage in the selected reservoir and that, due to a favourable CO2 miscible displacement mechanism, high oil recovery and storage capacity can be achieved, which leads the demonstration project to be economically profitable if prices of crude oil and CO2 remain above certain values.
Integrated Steam Generation Process and System for Enhanced Oil Recovery
Authors: Betzer-Zilevitch M. 
Published: February 2011

Abstract
Steam injection into deep underground formations has proven to be an effective method for EOR facilities producing heavy oil from non-minable oil-sand formation. It is typically done through SAGD, Steam Drive or by CSS. Most facilities generate waste liquids and consume natural gas. This paper proposes a method and system for producing steam for extraction of heavy bitumen with zero liquid discharge and with the ability to consume low grade fuel. The presented system includes "Direct Contact Steam Generation" (DCSG) used for direct heat transfer between combustion gas and contaminated liquid phase water for steam generation. The DCSG can be integrated into a commercially available pressurized boiler or gasifier for internally mixing the low quality water with the combustion gas and transferring the liquid water to gas. The DCSG can also be a separate entity, allowing the use of existing atmospheric boilers (like OTSG or industrial boilers). To recover the heat and the water from the DCSG discharge and to use it to generate additional BFW (Boiler Feed Water) for steam generation, a commercially available water distillation unit can be used: like an evaporator, MED (Multi Effect Distillation), MSF (Multi Stage Flash) or MVC (Mechanical Vapor Compressor). The water treatment plant discharge brine is recycled and consumed by the DCSG. Another advantage of the process is its ability to consume highly contaminated oily water and feed them directly to the DCSG. This capability simplifies the oil-water separation and reduces the amounts of chemicals normally used in this processes. The presented system can be integrated into an existing project as a new phase, with the advantage that all the liquid waste generated by old phases can be consumed by the DCSG providing an overall ZLD facility. The sludge waste of an existing hot or warm lime softener water treatment plant can be recycled to the combustion stage or to the DCSG and used to remove sulfur with petcoke or coal fired systems. Another advantage of the proposed solution is that any field facilities (like the pads, injection and production wells) will be unchanged, and will be similar design to standard well known facilities. The paper shows a clear solution to achieve an effective ZLD system that can use low grade water and low grade fuel.