bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stimulation’s Influence on Production in the Haynesville Shale: A Playwide Examination of Fracture-Treatment Variables that Show Effect on Production
Authors: Modeland Neil , Buller Dan , Chong King Kwee 
Published: December 2011

Abstract
In most developing shale plays, there is a learning curve for determining which factors best affect well production and yet still leave them economical. Advancing up this curve can take years to achieve as operators adopt a baseline treatment and th en adjust certain specific variables to find the best economic solution. However, by evaluating the reservoir on a playwide basis, the ability to find the optimal treatment method can be expedited, benefiting the operators by allowing them to achieve better wells earlier in the play’s development. Though many factors can hold a major influence (e.g., wellbore placement, rock properties, and flowback procedures), this study will review the production impact of specific variables of the fracture treatments, including well location. Using public production data with a database of stimulation treatments for several hundred wells in the Haynesville shale, variables such as pumping rate, volumes, proppant (type and volume), frac stage designs, base fluid, and surfactant usage can be analyzed to find which ones produce a positive effect on a well’s production. In addition to a well’s overall production magnitude, in the majority of the shale plays, regulating the decline of the production curve sometimes has been a crucial element in achieving the estimated ultimate recovery needed to make the play development economical. The stimulation-variables database will also be investigated to determine which factors can have an influence on ensuring a production curve’s decline will level off at a higher percentage of its initial production. By selectively identifying and grouping wells inside and outside the core area of the play, this study distinguishes which variables are positively affecting production while reducing the masking effect caused by geographic location. Conventional fracturing theory is applied to offer explanations of what might be occurring inside the reservoir or fracture system to make these findings hold true (or, at least, plausible).
Fracturing in the Oil-Sands Reservoirs
Authors: Yuan Yanguang , Yang Baohong , Xu Bin 
Published: December 2011

Abstract
Based on its deformation properties, Alberta oilsands reservoir material is classified as an interlocked sands. It possesses relatively high initial friction strength and exhibits a significant dilation tendency once it is shear-mobilized. How does such a medium behave under high injection pressures? Using analytical derivations and numerical simulations, this paper illustrates the evolving shear-induced failure and tensile-dominated fracturing behavior in the oilsands. It concludes that the fracturing process is a combination of shear dilation and tensile parting at micro scales. Laboratory and field data exist to support the theoretical observations. Finally, a discussion will be given about impact of such fracturing behavior on the reservoir engineering processes. It will shed light on proactive utilization of the dilation for the in-situ oilsands development.
Analyzing Variable Rate/Pressure Data in Transient Linear Flow in Unconventional Gas Reservoirs
Authors: Liang P. , Mattar L. , Moghadam S. 
Published: December 2011

Abstract
Unconventional gas wells often show linear flow during their transient period, and this transient behavior can last for several years. Currently industry uses typecurve matching technique to analyze this linear flow. The typecurves in common use are based on the assumption that wells produce at constant rate. However, most of the time, the production rate is variable, and in fact is closer to constant pressure operation. The constant pressure typecurve is useful but not suitable when both rate and pressure vary. It is necessary to have an easy-to-use method for analyzing variable rate/pressure data in linear flow.
There are two objectives for this paper. First, it serves to review the formulation, typecurve, specialized plots and superposition time that are used to analyze transient linear flow. It helps readers gain a deeper understanding of the theory. Second, it serves to illustrate a practical and effective way for analyzing variable gas production data.
In this development, we studied the effect of skin on the typecurve and on the specialized plot. We converted the constant pressure solution to its constant rate equivalent by using material balance time and found it to be acceptable for all practical purposes. We converted real time to corrected pseudo-time to account for variable gas properties, and found the effect to be small in the analysis of actual production data. We investigated the effect of outliers on superposition time. In the end, we proposed an approach to analyze variable rate/pressure data during transient linear flow and confirmed the validity of our methodology using synthetic data that generated in numerical models.
Benefits and Technical Challenges of Downhole Steam Generation for Enhanced Oil Recovery
Authors: Castrogiovanni Anthony , Fitzpatrick Nick , Ware Charles H. 
Published: December 2011

Abstract
Steam generated at the surface is currently the most common technology for in-situ thermal stimulation of heavy oil, however it has significant limitations due to heat loss that make it uneconomic for some 2 trillion barrels of deeper heavy oil resources. Downhole steam generators (DHSGs) have the ability to unlock these deeper deposits and allow steam to be used where it was previously not economical. A brief review of recent advances in DHSG technology and a description of potential applications using thermal oil recovery modeling and simulation are presented here. The DHSG technology described can be particularly suitable for recovering a number of known heavy oil deposits around the world that have experienced low recovery efficiencies through primary and secondary (water flood) production methods. These deeper resources typically require thermal stimulation to reduce viscosity in-situ for improved production volumes. Cost estimates and economic projections were developed based on a full green field project using production estimates obtained from STARS, a widely accepted heavy oil simulation program. Simulations and associated economic studies for the fields modeled, assuming the deployment of DHSGs, showed viable economics for all cases at both USD $75/bbl and USD $100/bbl 2009 WTI oil prices. The technological constraints of deep heavy oil production may be removed by further development of DHSG technology including direct-fired, umbilical-supported downhole natural gas fired systems that can be operated without maintenance for long periods of time. DHSG technology development activities are presented and specific issues relating to previous unsuccessful efforts are discussed. Finally, a new generation of DHSG technology is introduced and key design and operating problems with proposed solutions are presented. The uniqueness of the downhole environment is discussed along with the special requirements imposed on a downhole combustion system as a result. Technical challenges include tool positioning and inaccessibility, installation and operational safety, pressure management, and flame stability & control. Advances from the aerospace industry are also discussed as they pertain to robust combustion system development and downhole tool design which help enable a broad range of operating pressures and flow rate turndown. The demonstrated potential for DHSG technology to create optimum steam and EOR gas mixes that are tailored for a given reservoir may provide the basis for a new generation of thermal in-situ EOR technology to unlock deep heavy oil resources as well as those in environmentally challenged locales such as offshore or under arctic or permafrost environments.
Applicability and Assessment of Micro-Wave Assisted Gravity Drainage (MWAGD) Applications in Mehsana Heavy Oil Field, India
Authors: Jha Ashutosh Kumar , Joshi Nitin , Singh Aaditya 
Published: December 2011

Abstract
Exploitation of extra heavy oil resource will be the main R & D challenge in the future. In India Mehsana oil field is the one of the extra heavy oil belts. In such type of fields advanced EOR is of primary concern to increase the recovery. Apart from conventional thermal methods this paper discusses about the commercialization and broad application of (MWAGD) as alternative thermal method in the Mehsana oil field. In this study, applicability of microwave heating for heavy oil from Mehsana heavy oil field was experimented and analyzed quantitatively. In this paper a core sample of Mehsana field is taken and heated with the microwave energy provided by a microwave source consisting of magnetron tubes to generate the microwave power. Micro-Wave radiation is non-ionizing so requires high frequency current (3000 MHz) which causes friction by vibration of molecules which results in dielectric heating of the sample. In this experiment heat transfer between microwave source and core is described quantitatively. Temperature and viscosity profile of the gravity drained oil are observed graphically and analytically. Effects of initial oil and water saturations, wettability, porosity, permeability are discussed with respect to the drained oil. Economic evaluation is also done by comparing the costs in USD/barrel between the above proposed method and the method which is being run presently i.e. Steam Assisted Gravity Drainage (SAGD). In this paper authors have also shown the work-how of applicability of MWAGD in the Mehsana field in present scenario. MWAGD is cost effective than the conventional EOR methods. It is also more efficient and less time consuming as there is speedy heat transfer by dielectric heating. MWAGD does not cause any consequential damage and provides greater oil displacement efficiencies. Also, the heavy deposit of residual coke or carbon is rooted out.
Evaluation of Electric Heating on Recovery Factors in Extra Heavy Oil Reservoirs
Authors: Gasbarri S. , Diaz A. , Guzman M. 
Published: December 2011

Abstract
Most of the world hydrocarbon reserves represent extra-heavy oils. Exploitation of most of these reservoirs has not been carried out mainly due to the difficulty to produce the high-viscosity of extra heavy oils. Cold production can be achieved in the Orinoco Oil Belt through advanced horizontal wells. However, in many cases the drawdown exerted creates gas or sand production problems or excessive water production when an aquifer exists. Primary recovery factor under these conditions rarely go beyond 6%; and 3% in the presence of an active aquifer.
On the last decade several thermal mechanisms have been studied to increase the recovery of these types of reservoirs. This study analyzes the effect of bottom-hole electric heating on the production and recovery factors of extra-heavy oil reservoirs. The study was carried out by numerical simulation, analyzing the most influential parameters through an experimental matrix of 24 cases run in a horizontal well of 2000 feet. Four types of oils were studied, 8.1, 10, 12 and 15°API gravity. Reservoir thicknesses used were 300 feet and 80 feet. Two different heating rates were used (1.6e07 and 5e07 BTU/Day). The boundary conditions used in the model correspond to the installation of a typical downhole pump in Orinoco Belt. Several parameters were analyzed such as pressures, temperatures, viscosities, production rate, gas-oil ratio, in order to determine the effect of the heating.
Based on this study, electric heating represents a good option for good sand quality reservoirs with low API gravity oils where a small change of temperature generates great change in viscosity. Special grid refinement must be performed within the wellbore in order to allow the simulator to accurately estimate the properties and conditions in this area where significant changes occur. Electric heating reduces the viscosity near wellbore and increases the bottom-hole pressure avoiding excessive gas liberation near the well. This creates favourable conditions for production delaying an oil relative permeability drop. Based on the simulations studied, this method increases the recovery factor up to 60% the one obtained in cold production for a typical extra heavy oil.
Geomechanics for the Thermal Stimulation of Heavy Oil Reservoirs–Canadian Experience
Authors: Yuan Yanguang , Xu Bin , Yang Baohong 
Published: December 2011

Abstract
This paper will cover both caprock integrity and reservoir deformation, drawing from our years of experience in working with the heavy oil/oilsands industry in Alberta, Canada. Theoretical principles are described, analytical derivations made and field examples given, all to help illustrate the fundamentals and summarize the learnings in proactive utilization of geomechanics to enhance the reservoir performance and proactive consideration of geomechanics to ensure the caprock integrity. Topics include dilation tendency and fracturing behaviour in the oilsands, major geomechanical work components for the caprock integrity analysis/design, mini-frac tests and nonlinear coupled thermo-hydro-mechanical processes.
Method of Minimizing Liner Expansion Issues in Horizontal Thermal Applications
Authors: Cavender Travis , Hunter Tim , Pipkin Robert 
Published: December 2011

Abstract
Thermal recovery methods used in the exploitation of heavy-oil and bitumen reservoirs can create severe expansion problems on liner and production tubular equipment caused by the effects of thermal expansion. This is more often the case when using horizontal sandface completion configurations in steam flood, cyclic steam, and steam-assisted gravity drainage (SAGD) applications.
Many single lateral and multi-lateral horizontal heavy-oil wells are produced initially using cold ambient reservoir heavy-oil production methodologies where liner expansion is not a concern. However, with proper up-front planning and engineering, these wells could be converted to thermal EOR producers with the addition of thermal expansion devices placed within the liner assembly when initially completed. These expansion devices are engineered to activate when exposed to elevated temperatures once the thermal operations begin and do not require mechanical activation or well intervention. Since these devices are deployed with the liner assembly, they must also be capable of handling compression, tension, and torque loading across the liner during the deployment phase.
These devices can be deployed with the slotted liner/sand screen applications or can be used with production or concentric tubing configurations. This paper will present use of this new device in different wellbore configurations found in various thermal recovery methods.
Viscosity Predictions of Kuwaiti Heavy Crudes at Elevated Temperatures
Authors: Alomair Osamah , Elsharkawy Adel , Alkandari Hassan 
Published: December 2011

Abstract
Viscosity is a key property for evaluation, simulation and development of petroleum reservoirs. The accurate prediction of viscosity will be helpful for, production forecasting, designing future of thermal recovery processes. Reservoir oil viscosity is usually measured isothermally at reservoir temperature. However, at temperature other than reservoir temperature these data are estimated by empirical correlations. Here, based on results of viscosity measurements of 33 heavy crude oil samples of API gravity ranging from 10° and 20° degree, at 68 °F collected from various areas of Kuwaiti oil fields, and tested at 68 to 320 °F. A new correlation has been developed. The validity and accuracy of this correlation has been confirmed by comparing the obtained results of this correlation with other ones along-with the experimental data. The result were satisfactory, in contrast to other correlations which were mostly developed for significantly lighter oils at average reservoir temperatures. Most of them cannot reasonably predict the heavy oil viscosity at elevated temperatures.
Comparative Analysis of Electromagnetic Methods for Heavy Oil Recovery
Authors: Bogdanov Igor , Torres Jose Antonio , Kamp Arjan , Corre Bernard 
Published: December 2011

Abstract
Energy producing companies increasingly exploit non-conventional hydrocarbon resources such as heavy oil, bitumen or shale. Because of their large viscosity, production of oil from such resources is frequently done through reservoir heating, most often via steam injection. In some cases the steam injection is not a good alternative, especially, for tar sands. A better suited technology may be electromagnetic heating (EMH) assisted oil recovery.
Different physical mechanisms underlie the heating according to the frequency of electromagnetic (EM) field. For instance, low-frequency heating (LFH) based on the Joule effect is well-known for environmental applications and has been field-tried recently. So-called inductive heating used for many years in induction furnaces is the process where Foucault (eddy) currents generated within a load result again in Joule heating. Finally, high-frequency heating (HFH) consists of in-situ dielectric heating resulted from rotation with friction of polar molecules in the EM field.
An EM field facility is installed normally in a well bore, the EM power being converted into heat inside reservoir which leads to the increase of local temperature. The conspicuous advantages of all EMH methods – avoidance of well low injectivity/connectivity and well injection pressure related problems – are complemented with in-situ heat generation and particularly, water evaporation (e.g. during HFH). Nowadays, according to literature sources, the EMH models of two types are in use. The first one is a class of analytical approaches using relatively strong assumptions mainly concerning to heating power distribution. They provided reference solutions for numerical models and an order-of-magnitude estimation procedure which is feasible for large-scale models.
Being geometrically more complex the large-scale models have been developed for simulation of more realistic EM power distribution. These models provided a framework to critically analyze the processes of oil recovery. The obtained numerical results are used for subsequent consideration of advantages and application limits for each of considered EMH methods, i.e. for low- and radio-frequency heating assisted heavy oil recovery.
The comparative analysis of different methods of EMH assisted oil production provided by this work is an important feature in process design considerations.
Optimal Voidage Replacement Ratio for Communicating Heavy Oil Waterflood Wells
Authors: Vittoratos E. Steven , Coates R. , West C. C. 
Published: December 2011

Abstract
Accumulated field empirical observations suggest that water injected to displace heavy oils forms in the reservoir channel-like communication paths from the injectors to the producers. The evidence comes from mass balances and, more recently, from 4D seismic monitoring of heavy oil waterfloods. The reasons for this are multifold, including unconsolidated sand formation dilation about injectors due to slow pressure diffusion in heavy oils, reservoir heterogeneities in permeability and saturation, sand production from the reservoir, and the instability of the displacement interface due to the high mobility ratio between water and heavy oil. Once formed, the channels can degrade further economic recovery of the heavy oil as the water oil ratios increase significantly. This study reports on initial results from a laboratory program to test the optimal reservoir management response upon formation of such communication paths in heavy oil waterfloods.
To physically simulate reservoir waterflood behavior under the existence of a communication path, a large scale ‘big can’, five feet long with a ten inch by ten inch cross section, was designed and constructed that allowed for the creation of a highly reproducible communication path from the injection to production end of the can. This was a mandatory requirement for accurate comparison between alternative reservoir management strategies whose differences would otherwise be hidden by variations in random communication path formation. The design has proven to be highly successful. Our first objective was to test whether the industry paradigm and the regulatory mandated practice of maintaining a voidage replacement ratio (VRR) of one throughout the entire waterflood is optimal. Live 18.6 API Alaska North slope oil was used to saturate four Darcy sand that filled the big can. Upon creation of the communication path, three VRRs were tested: 1.0 (conventional waterflood), 0.7 (hybrid waterflood/solution gas drive), and 0.0 (conventional solution gas drive). The VRR=0.7 run outperformed the conventional VRR=1.0, suggesting that periods of under injection may improve heavy oil waterflood response upon formation of injector-producer communication.
Probabilistic Forecasting and Model Validation for the 1st Eocene Large Scale Pilot (LSP) Steamflood, Partitioned Zone (PZ), Saudi Arabia and Kuwait
Authors: Osterloh W. Terry , Mims Don S. , Meddaugh W. Scott 
Published: December 2011

Abstract
The 1st Eocene heavy oil reservoir (1E) in the Wafra field is a candidate for steamflooding due to its world-class resource base and low estimated primary recovery. However, industry has little experience in steamflooding carbonate reservoirs, which has prompted staging of several 1E steamflood tests, the latest of which is the Large Scale Pilot (LSP) started in 2009. To assist in facilities design, help understand expected performance in a very heterogeneous reservoir, and provide input to early decision analyses, numerical thermal simulation was used to generate probabilistic forecasts. Once adequate pilot history was available, the model was validated using probabilistic methods.
The LSP model was comprised of 1.5 MM cells, which allowed maintenance of adequate resolution and proper boundary conditions in the pilot area. Parallel computation enabled a probabilistic workflow to be implemented with this large thermal model.
In this paper we highlight the methodologies and inputs used to generate the probabilistic forecasts and validate the model. Major results of this work include the following: 1) in contrast to many green-field forecasts that are often optimistic, the LSP forecasts were instead conservative, likely due to unique aspects of the forecasting methodology, proper selection of uncertainty ranges, and the relatively high density of input data for model construction, 2) wide variations in production metrics were forecast, indicative of a highly heterogeneous reservoir, and 3) despite this heterogeneity, oil recovery mechanisms and recovery levels were comparable to those observed in steamfloods in sandstone reservoirs.