bluuebunny/crossref_metadata_2025_split huggingface dataset:
Measurement of Relative Permeability of Coal to Gas and Water
Authors: Ham Y.. , Kantzas A.. 
Published: November 2013

ABSTRACT
Relative permeability of coal to gas and water is an important variable in coalbed methane reservoir development as it is required for reserve estimation and field production planning. In this study, gas-water relative permeability of two coal samples: Grande Prairie (GP) and Goldsource (GS) were determined by the Johnson-Bossler-Naumann (JBN) method, which is widely used for petroleum reservoir rocks.
An experimental apparatus was designed, built, tested, and commissioned for various two-phase gas-water relative permeability measurements. The gas phases used were helium, methane, and carbon dioxide in this order of adsorbing strength on coal and the water phase used was formation brine. Forty-eight drainage and imbibition displacement runs were carried out on the two coal samples using helium-brine, methane-brine, and carbon dioxide-brine combinations at three different operating pressures (100, 300, 400 psi) at a constant overburden pressure (800 psi), and the results were analyzed and plotted on drainage and imbibition curves.
Imbibition relative permeability showed that the irreducible water saturation correlated with pressure and the absolute permeability of the coal samples changed after each experiment. The GS coal sample showed a greater two-phase flow saturation range than the Grande Prairie coal sample. In both cases, the relative permeability to gas was low and high for water. The coal samples tended to become more water-wet at higher pressures in the case of adsorbing gases, namely methane and carbon dioxide but in the case of non-adsorbing gas helium, higher pressure prevented the inflow of water into the smaller pores leading to a decrease in irreducible water saturation with an increase in pressure. The drainage experiments were highly unstable based on the Instability Number calculated. The resulting relative permeability curves showed oscillation.
From this study, it was concluded that coal relative permeability to gas and water depended on the nature of gas, the operational pressure, and fluid-mineral interactions.
Dynamic Positron Emission Tomography: Application to Imaging Fluid Mobility in Fractured Cores
Authors: Maucec Marko , Dusterhoft Ron , Rickman Richard , Gibson Ron , Buffler Andy , Stankiewicz Maciek , van Heerden Michael 
Published: November 2013

Abstract
Positron emission tomography (PET) continues to have wide-ranging medical application and is based on the detection of gamma radiation emitted from the decay of certain types of radionuclides. Modern PET scanners produce 3D images of the radiation source, in discrete time steps, using tomography analysis. This paper presents an application of PET for studying fluid mobility in pressurized low-permeability rocks in the presence of natural fractures. This technique uses a high-resolution PET scanner and image reconstruction based on filtered back-projection. Traditional techniques have been limited to pressure measurement of fracture conductivity and effective permeability, but little is understood about the dynamic flow and velocity profiles within the fracture.
The objective of this work was to determine if it is possible to measure the dynamic (e.g., time-lapse and continuous) distribution of fluid flow as a function of the overburden stress. PET imaging was applied to the flow of brine solution, which was tagged with 18F-fluorodeoxyglucose (FDG) positron emitting radionuclide, through nonfractured sandstone and naturally fractured shale cores. A special composite container was manufactured to sustain high-pressure conditions and minimize the absorption of emitted gamma rays. The experimental apparatus is described, and it is demonstrated that 3D images obtained with a grid resolution of 2 × 2 × 2 mm3 allow clear determination of the fluid flow rate through the core as a function of overburden pressure and time. PET images are direct observations of the radiation source and allow an unambiguous determination of the fluid distribution in the core. The results of this research can be used to validate the numerical modeling of fluid flow through fractured rock matrices, to enable more accurate estimates on the directionality of fractures from the fluid distribution as a function of time, and to obtain more quantitatively sound estimates of fracture connectivity.
Moving CBM Reservoirs into Production – Developing a New Workflow
Authors: Sidiq Hiwa , Khalili Ahmad Dehghan 
Published: November 2013

Abstract
There have recently been extensive attempts to better model and simulate coal bed methane (CBM) reservoirs - something which is particularly pertinent to Australia which has an estimated 198 billion cubic meters (Bcm) of CBM resources and Queensland where AUS$50 billion worth of CBM projects are currently in progress.
Yet, while most reservoir simulators are equipped to simulate fluid flow in CBM reservoirs, there is a need for a workflow that is better able to locate the sweet spots in CBM. To this end, this paper will examine recent technical developments in reservoir modelling and how modelling tools can be better utilised to optimise production in CBM reservoirs through simulation.
The paper will look at the challenges in collecting the right amount of data to compile an accurate characterisation of a preexisting fracture network (cleats) and its structural complexities. The current low gas prices sometimes prevent the acquisition of such data – data that is an essential input to drilling strategies, fracture programme design and well spacing.
The paper will also examine how the transport along a wellbore is not only controlled by the fractures around the well but also by the drained volume. In such cases, the pre-existing fractures and their reactivation during the fracturing stage are not always sufficient to determine the amount of gas that can be recovered during production.
With this in mind, the paper will also look at the challenge of generating a good estimation of the size of the gas-in-place within CBM reservoirs and the role of reservoir modelling and simulation within this area.
A Holistic Approach to the Appraisal Stage of Shale Gas Resources
Authors: Navarette Mike , Chorn Larry , Maucec Marko 
Published: November 2013

Abstract
Source rock reservoirs (SRRs) are found in conventional oil and gas basins. The exploration for and the evaluation of an SRR depends on the geology, geochemistry, petrophysical, and geomechanical parameters; as well as economic constraints in the targeted area. The SRR exploration methodology is fundamentally different from conventional exploration as SRR objectives require a program that includes a data-acquisition focused effort in the early stages of exploration and appraisal. We highlight a holistic approach to shale gas development that has been developed in detail, encompassing more than 25 years of Halliburton experience in U.S. shale plays. Unconventional SRRs impose significant engineering constraints because reserves are spread out across large compartmentalized, stacked or layered reservoirs, which are highly heterogeneous (faulted and fractured) and confine wide ranges of mineralogy. The objective of our work is to provide a better understanding of the SRRs' reservoir quality and deliverability to assist with maximizing well productivity, improving hydraulic fracturing stimulation, and optimizing drilling and completion efficiency. This paper identifies critical paths and key technical elements or tasks associated with SRR basin screening, appraisal, and field development. Previous data acquired (seismic, logs, cuttings, mud logs, and well files) and commercially successful analogs are used to evaluate and benchmark potential hydrocarbon reserves. A methodical approach that addresses the following key tasks is presented: Determine critical SRR attributes.Map selected attributes in the SRR model.Establish best reservoir targets (sweet spots) with well location and orientation.Maximize the stimulation potential and recovery factor.
Our work provides a proven road map for the evaluation and development of SRRs. Critical paths with the associated key technical elements address and provide a project scope of challenges, which enables a holistic solution to successful unconventional SRR development.
Novel Chemical Stimulation Techniques to Enhance Coal Permeability for Coal Seam Gas Extraction
Authors: Turner Luc G. , Steel Karen M. , Pell Stephen D. 
Published: November 2013

AbstractPermeability is a key controlling factor for gas migration in coal seam reservoirs and has invariably been the barrier to economically viable gas production. A large variety of completion techniques have been utilised in coal bed methane (CBM) production with varying degrees of success. Low permeability stimulation treatments primarily consist of hydraulic fracturing and multi-lateral horizontal wells. High stress, cleating and low Young's Modulus in coal can lead to complex and inefficient fractures compared to conventional reservoirs. The creation and transport of fines due to shear failure can reduce the fracture conductivity and thus coal permeability. The unique structure of coal may offer opportunities for the development of new methods for creating gas flow paths for low permeability coals.Coal seams contain upwards of approximately 10 wt.% mineral matter with a significant proportion contained within the natural cleat system. This study has involved characterization of the cleat system in a core sample from the central Bowen Basin. It was found that the volume of cleats was around 0.52% with around 73% of the cleats mineralized. LTA-XRD analysis found the minerals in the whole coal to be quartz, kaolinite, clays, calcite, apatite and bassanite. SEM-EDS analysis found that calcite and kaolinite dominate the mineralology of the cleats. The removal of these minerals is thought to create additional gas flow paths whilst maintaining the structural integrity of the coal. Furthermore, given that coal is reactive toward oxidants there is the possibility to undergo controlled reaction of the macromolecular coal structure to further enhance permeability.Batch leaching experiments with HCl were effective at dissolving the Ca-bearing minerals. Of the oxidants studied, potassium permanganate appeared to break down the coals structure, producing a significant level of organics in solution Both hydrogen peroxide and Fenton's reagent didn't yield organics in solution although a slight mass loss was found, indicating that oxidation may have occurred with CO2 produced as the reaction product. Permeability tests were performed on a Bowen Basin core sample with HCl solutions. An increase of 7 wt% was observed, however, permeability was found to decrease again on account of the confining pressure exceeding the cleat pressure.
Lessons Learned from Engineering Analysis of Fracture Injection Tests from Different CBM Reservoirs
Authors: Pankaj P.. , Sinha M.. , Barasia A.. , Venkateshwaran R.. , Shado O.. , Nawaz Sami , Ghosh Baijayanta , Kumar Vikash 
Published: November 2013

Abstract
With the growing energy demand, operators are looking at exploiting every source of energy and have intensified exploration in coalbed methane (CBM) reservoirs. In the area under consideration, hundreds of wells have been drilled to a few thousands of feet depth covering multiple coal seams. Most of these coal seam reservoirs are CBM reservoirs that need massive dewatering to economically produce the methane gas adsorbed on the coal surface. Hydraulic fracturing has become an important tool that not only enables accelerated dewatering to reduce reservoir pressure to the critical desorption pressure, but also creates a conductive path for gas production and minimizes non-Darcy effects.
However, the art of hydraulic fracturing in these unconventional reservoirs is not easy to master. Complex formation behaviors such as poroelasticity, nonideal pressure leakoff, state of formation damage, orientation of cleat system, high fracture gradients, etc. constantly challenge the fracturing design and execution in these unconventional reservoirs. Neglecting pressure responses and having a poor understanding of formation characteristics can compromise the placement of optimized hydraulic fractures, and, ultimately, production results.
Hydraulic fracture engineering analysis was performed on all the CBM wells in two exploratory fields and one development field of a CBM basin have been consolidated; the analysis included approximately 40 fracture treatments from these three different fields. Fracture pressure diagnostics such as G-function plots, leakoff mechanisms, and closure pressure analysis, were part of the design, execution, and evaluation cycle to establish and characterize the hydraulic fractures (HF) in the different coal seams. Post-fracture studies completed the design execution and evaluation cycle.
Innovation, Motivation, and Fear: A Novel Perspective for Unconventional Oil
Authors: Bunio Gary L. , Gates Ian D. 
Published: November 2013

Abstract
The focus of this paper is innovation in oil sands recovery technology. Canada hosts the third largest reserves of petroleum in the world, mostly in heavy oil/oil sands reservoirs. The two commercial in situ recovery technologies, Cyclic Steam Stimulation and Steam-Assisted Gravity Drainage, were both invented &gt;30 years ago; both use large amounts of water and emit carbon dioxide. Industry is facing a critical point where it is imperative to find new technologies. It has been a significant challenge to find new processes with large reductions of water and carbon dioxide emissions. Another critical issue is adoption time scale – in the past, new technologies have taken 10–20 years to become commercial – this pace must be accelerated. The oil sands industry needs to improve the innovation cycle of oil sands extraction technologies. The objective here is to understand how to do this, to describe factors that encourage and discourage innovation, and to recommend strategies to enable and stimulate non-incremental innovation. It is interesting to note that despite only a few oil companies still having research laboratories and permanent research staff, abundant potentially inventive scientific, engineering, and management staff exist in oil companies. So the question becomes: what is preventing them from developing a plethora of inventions and bringing creativity to issues confronted by the oil sands industry? It does not appear to be only a technical issue but also a social one. Market, resource, and social issues lead to this result: most petroleum funding directed at near market iterations, short term incentives (increasing shareholder value), government funding matched to current industry activity and thus linked to market forces, low funding levels, culture of risk adversity and fear of risk, innovation curbed by regulatory factors or internal work overload, and high costs due to investment, variable resource quality, high capital costs, and oil price volatility.
Monitoring Well Integrity and Groundwater Protection with Innovative Logging Practices in Unconventional Horizontal Wells
Authors: Foianini I.. , Nurhayati T.. 
Published: November 2013

Abstract
Hydraulic fracturing and horizontal drilling have catalyzed the recent United States (US) hydrocarbon production "renaissance," spearheaded by unconventional asset development. The increase in oilfield activity, however, has exposed groundwater contamination as a potential environmental concern associated with the use of these two technologies. Government and state agencies have revisited regulations to help ensure well integrity, but operational success is currently limited because of tool deployment and centralization issues in horizontal wellbores.
The combination of acoustic logging and conveyance technologies with field engineering insight has created a unique solution to well integrity monitoring in horizontal well intervals. Various successful logging services have been performed in wells producing from the Marcellus shale play in Pennsylvania.
A well operator needed to determine proper cement placement between different fracturing stages to avoid unwanted fluid movement throughout the wellbore annulus. The logging tool string, composed of ultrasonic scanning and cement bond log (CBL) tools, was transported through the horizontal wellbore using a tractoring device.
Tool centralization, which is critical to accurate operation of acoustic tools, is difficult to achieve in horizontal wellbores because of the influence of gravity and friction forces. This challenge was overcome by integrating centralization equipment for additional tool support while maintaining wireline tension limits.
This case study discusses the operational background and challenge, creation of this innovative tool setup, and the effects this service will have on performing successful well integrity monitoring in additional unconventional horizontal wells.
Vitrinite Reflectance Versus Pyrolysis Tmax Data: Assessing Thermal Maturity in Shale Plays with Special Reference to the Duvernay Shale Play of the Western Canadian Sedimentary Basin, Alberta, Canada
Authors: Wust Raphael A. , Hackley Paul C. , Nassichuk Brent R. , Willment Nicole , Brezovski Ron 
Published: November 2013

Abstract
In unconventional, self-sourced sedimentary rocks, organic matter type and maturity and therefore the hydrocarbon production potential, are the most critical parameters when evaluating unconventional hydrocarbon resources. Several methods exist that determine the maturity level of sedimentary rocks and the organic matter. Organic maturity is commonly determined by vitrinite reflectance (%Ro). Vitrinite is a type of maceral that is derived from higher order plants. In rock with little or no vitrinite, bitumen or other organic matter type reflectances are measured and calculated to a normalized reflectance value (%Ro). Measuring vitrinite/bitumen reflectance is time-consuming and subject to the interpretation of the analysts. Alternatively, organic matter type and maturity are also measured using Rock Eval or equivalent pyrolysis techniques. The temperature (Tmax) at which thermal cracking of heavy hydrocarbons and kerogen reaches the maximum depends on the nature and maturity of the kerogen and indicates the level of thermal maturity. Pyrolysis results are independent of an operator although the data output may still require validation. In order to compare data from these two techniques, a study from the Barnett in 2001 produced a conversion formula to calculate %Ro from Tmax data. The conversion formula (calculated Ro = 0.0180 × Tmax − 7.16) has been used extensively in basins worldwide despite the fact that the correlation was produced for the Barnett shale. Here we present new maturity data (&gt;100) (%Ro and Tmax) within the Duvernay Formation in Alberta, Canada, which is compared to data using the conversion formula. The Duvernay Formation of the Western Canada Sedimentary Basin is an Upper Devonian (~360 Ma) source rock which has been praised as one of the most promising oil/gas resource plays in Canada. Since late 2009, land sale activity has seen over $1.4 Bn spent in Alberta with land purchases focused in the Pembina and Kaybob areas. The total organic carbon (TOC) content of the Duvernay Formation can exceed 20 wt% in areas of low maturity but on average, the dark shales have TOC contents ranging between 4–11 wt%. TOC is a key indicator of hydrocarbon generation potential. In this study, we discuss the details of both analytical techniques, findings of the organic petrography, bitumen reflectance data and corresponding Tmax data. The data is also compared to calculated Ro values and problems using the formula are highlighted. In addition, the data is put into perspective of production information and the hydrogen-generative models (initial production data). The results show that inherent problems are manyfold and conversion calculations should be avoided in new formations where a conversion formula has not been established.
Surface Well Test of Methane Gas Saturation in CSG Lateral Completions During Dewatering Using Raman Spectroscopy
Authors: Mazumder S.. , Scott M.. , Pope J. M. , Morgan Q.. , Ramsay P.. 
Published: November 2013

Abstract
This paper describes application of an established coal seam gas (CSG) testing technology to the reservoir and production conditions prevalent in the Bowen basin, Queensland, Australia. The technology involves using Raman spectroscopy to measure gas partial pressure in single phase fluids produced under pressure from dewatering coal seam gas wells. The technique's efficacy has been described extensively in technical literature. Prior tests have been conducted on permeable coals that produce several hundred BWPD. Applying the technology to tight coals in the Bowen basin is not considered straightforward.
Effects of High Pressure-Dependent Leakoff (PDL) and High Process-Zone Stress (PZS) on Stimulation Treatments and Production
Authors: Ramurthy Muthukumarappan , Towler Brian F. , Harris H. Gordon , Barree Robert D. 
Published: November 2013

AbstractHydraulic fracturing continues to be the primary mechanism to produce hydrocarbons out of unconventional reservoirs like tight gas sands, tight coals and shale reservoirs. Over the last few decades it has been studied extensively. However, all the issues that arise during a stimulation treatment have not been understood correctly, yet, leading to costly trial and error approaches to fix them. Assuming that a majority of the perforations (or sleeves) are open and there are no issues with the stimulation fluids, screen-outs and/or pressure-outs during stimulation treatments in any type of reservoir can be attributed to either high pressure-dependent leakoff (PDL) or high process-zone stress (PZS). With high PDL the end result will be a screen-out if it is not addressed properly. However, with high PZS, it is the first indicator and in conjunction with fracture gradient and local stress environment one can understand the reasons for pressure-outs or screen-outs. With high PZS pressure-outs are more common than screen-outs. The objective of this work is to clearly explain and quantify these reservoir-related issues and once identified present solutions such that screen-outs and pressure-outs can be avoided in re–fracture and new well treatments. The effect of damage zone and the fluid lag or negative net stress zones and their contribution to the fracture tip effects will be presented. This work will also clearly show that zones that exhibit high PZS (greater than 0.20 psi/ft), irrespective of the formation type, are economically poor producers.The tools for identifying these reservoir-related parameters include a diagnostic fracture-injection test (DFIT) and a grid-oriented fully functional 3D fracture simulator with shear decoupling. The relationship between high PZS and the local stress environments and their contribution to issues during a stimulation treatment are presented based on the analysis of 3000 plus DFIT's from the Rockies. Coal, tight gas sand and shale formations are part of the 3000 plus DFIT dataset presented in this work. Examples from coal and shale formations presented earlier by the author are referred in this work. Finally, guidelines (Ramurthy 2012) are presented such that stimulation treatments in high PZS zones that contribute to poor production can be avoided and high PDL zones that lead to good production can be optimized, thereby saving completion costs.