bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unconventional Oil Production from Underground Coal Gasification and Gas to Liquids Technologies
Authors: Perkins Greg , du Toit Ernest , Koning Bert , Ulbrich Andreas 
Published: November 2013

Abstract
The combination of underground coal gasification and gas to liquids technologies offers the potential to produce high quality synthetic oil and associated products from deep coal reserves that are unsuitable or uneconomic to extract using conventional methods. This paper provides a summary of achievements made over the past five years at the world's only Demonstration Facility where UCG and GTL technologies have been successfully integrated and operated to produce synthetic oil products. The process of UCG is described, along with the key features of the proprietary technology developed and operated by Linc Energy. A number of the experiences gained from operating multiple underground gasifiers over several years are outlined. The GTL facility at the Demonstration facility is described, along with selected results from operations of the gas conditioning unit and the synthesis of liquid hydrocarbons using the Fischer-Tropsch process. The products generated from the facility are summarised. In the second half of the paper an outline is provided of a commercial UCG to GTL facility and some of its characteristic performance parameters. Technology selection and project execution considerations for commercial scale plants are discussed. Finally, the global potential of UCG as a method for producing unconventional gas from deep coal is discussed and some of the challenges and opportunities for producing unconventional oil via integration of UCG and GTL are summarised.
Alternative Polysaccharide Fracturing Fluids for Harsh Reservoir Conditions
Authors: Zhou Jia , Legemah Magnus , Beall Brian , Sun Hong , Qu Qi 
Published: November 2013

Abstract
Guar and its derivatives are the most commonly used gelling agents in fracturing treatments. In the last few years, enormous price swings and supply shortages of guar have posed major challenges for service companies and operators. In addition, the fluid volumes in fracturing treatments have increased substantially, while water supply has become more of a public concern. Rather than paying to treat and dispose of produced and flowback water, operators would like to recycle it in subsequent stimulation operations. Carboxymethylcellulose (CMC) has been recommended as an effective alternative to guar system. However, CMC system can only be crosslinked under low pH environment and their application is limited with formation temperature up to 250°F and also in high quality water.
A readily available polysaccharide, Carboxymethylhydroxyethylcellulose (CMHEC) is presented in this paper to address the challenges of making a fracturing fluid in harsh reservoir conditions like high formation temperature and high-TDS produced water. Using a produced water sample with TDS over 200,000 ppm and total hardness as CaCO3 over 40,000 ppm as representative water, laboratory testing has demonstrated that the new polymer can be fully hydrated within 3 minutes, similar to the hydration rate of guar in fresh water. Furthermore, the resulting linear gel can be crosslinked with metal crosslinkers to achieve excellent rheology at various formation temperatures. The crosslink can also be delayed to minimize pipe friction. The fluid is compatible with other common stimulation additives, including scale inhibitors. Conventional oxidizing breakers can be used to effectively break down the fluids, leaving no formation or proppant pack damage.
This paper will discuss the evolution of the technology and present rheology results at various formation conditions.
Integration of Quantitative Rock Classification with Core-Based Geologic Studies: Improved Regional-Scale Modeling and Efficient Exploration of Tight Shale Plays
Authors: Marino Sonia , Herring Shanna , Stevens Kimberly , Petriello John , Handwerger David , Suarez-Rivera Roberto , Woodruff William 
Published: November 2013

Abstract
Assessments of unconventional plays typically rely on single property to property relationships to define drivers for economic success. These may include fracture corridors, organic-rich facies, and high thickness-permeability products. Unfortunately this concept has been rather elusive. To a large extent, the industry uses conventional reservoir thinking to explain unconventional field observations. This results in great confusion and the generation of local experience that cannot be transferred elsewhere. A new mental picture of tight shale plays is proposed which recognizes the role of geology to generate substantial variability in material properties across seemingly similar depositional units. Understanding that subtle changes in rock composition and texture associated to geologic processes (deposition, tectonics, and diagenesis) are responsible for substantial changes in reservoir quality and completion quality properties, and understanding that log responses are also affected by rock composition and texture allow defining a new pattern for relating geology, material properties, and logs, quantitatively.
A regional evaluation of reservoir quality, completion quality, and production potential was developed for the Haynesville shale over an area of 7,185 square miles. The study was supplemented with comprehensive core studies including measurements of petrologic, geochemical, petrophysical, and mechanical properties across all facies. Rock classes with unique properties of reservoir quality and completion quality were identified based on high-resolution logs, and related to the geologic model built from core observations. The distribution of the rock classes was then tracked throughout the basin. This approach allowed mapping the reservoir potential in a very effective manner.
Integrating geology with material properties on a rock class by rock class basis provides remarkable knowledge needed for the field development. While core extractions and seismic surveys are often conducted in isolated areas, this method also provides background information for selecting the most strategic locations for supplemental cores and seismic data. This methodology can optimize the early exploration phase of unconventional plays.
Recycling redundant coreholes
Authors: Young S. R. , Norton G. F. , Foo K. J. 
Published: November 2013

Abstract
In 2009, QGC (a BG Group business), began developing coal seam gas (CSG) feedstock for its new Liquefied Natural Gas (LNG) plant and required a subsurface model and field development plan to underpin the project's investment case. Fundamental to the modeling process was acquiring appropriate data to calibrate subsurface models and enhance confidence in their predictive quality. As part of an integrated reservoir surveillance strategy, specific pressure and temperature monitoring wells were required.
This paper describes the successful lab and field implementation of an innovative completion technique that converts suspended coreholes into reservoir and aquifer monitoring wells. The coreholes are re-entered and vibrating wire piezometers (VWP) attached to capillary coil tubing, are positioned and cemented in place alongside selected reservoir intervals. The well is then "plugged and abandoned" and the lease remediated to leave only a small surface footprint for the data logger and telemetry. The cement is effectively impermeable to fluid movement but possesses sufficient permeability to transmit reservoir pore pressure to an adjacent piezometer.
Recompletion of coreholes provides a cost-effective means of acquiring valuable downhole data while eliminating the need to drill a bespoke monitoring well in the same vicinity. Data over the reservoir interval (the Walloon Coal Measures) can inform and help resolve reservoir properties on a regional scale, understand contribution to flow and provide data points to pressure-match a reservoir model. Data over the aquifers within Springbok Sandstone and Gubbermunda Sandstone enables estimates of any CSG production effects on groundwater.
Regulatory Concerns for Sub-Surface Modeling of Unconventional Reservoirs
Authors: Tyson Stephen 
Published: November 2013

Abstract
Since computer modelling of petroleum reservoirs was developed in the late 1980's, the technique has become almost ubiquitous. But, most of the experienced geoscientists that really understand the capabilities of these models are sceptical about the predictive capability of reservoir modelling and acknowledge that even their best models are either highly subjective or are quantified guesses. In recent years a trend has been emerging in which reservoir models are increasingly demanded by regulatory authorities prior to development approval which raises the question: "What is a good reservoir model?"
This paper considers the concept of a ‘good model’ since, without clear guidelines on good models it is difficult to determine who is qualified to build a model or who is qualified to audit a model. The process of verification and validation of reservoir models is then considered and petroleum industry practices are compared with computer modelling in other industries. There is increasing public concern over the development of unconventional resources, and industry concern over possible litigation, so this paper suggests a set of acceptance criteria for sub-surface models with the aim of identifying procedures that are auditable, defendable and robust for adoption by regulators.
During the development of these criteria, a number of key areas in modelling workflows were identified as being of critical concern to the construction of a ‘good model’; model scope, prior elicitation, scale issues, and multiple scenarios. These four areas are discussed in detail and their impact on model quality and predictive capability are assessed. It is hoped that the topics highlighted in this paper encourage enlightened discussion, and ultimately consensus, on the concept of good quality sub-surface modelling of unconventional resources between the regulators and the industry.
Waterflooding in the Eagle Ford Shale Formation: Experimental and Simulation Study
Authors: Morsy Samiha , Sheng J. J. , Soliman M. Y. 
Published: November 2013

Abstract
Waterflooding is the cheapest and most profitable secondary recovery method that has been used for more than seventy years for conventional oil reservoirs. However, few studies have been done on its viability on unconventional tight formations especially shales. The objective of this paper is to study the potential of waterflooding in Eagle Ford shale formation through water imbibition experiments on reservoir rock samples and simulation study using Eagle Ford shale published data. In the experimental study, distilled water and 2% KCl brine solutions were examined to recover oil from different Eagle Ford shale reservoir samples. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. First, we studied the porosity of samples using CT Scanning. The average porosity of the studied samples varied from 1% to 5%. Second, we studied the spontaneous imbibition of the different used samples in distilled water and 2% KCl for one week. During the spontaneous imbibition, the maximum oil recovery was 19% from the samples placed in distilled water against 12% from the samples placed in 2% KCl brine solution. The higher recovery achieved by the distilled water was due to cracking from clay swelling which was not observed with the 2% KCl brine solution. The samples exposed to distilled water for one week during the spontaneous imbibition experiment showed more tendency to break down when low confining pressure was applied due to clay swelling. The simulation study using Eagle Ford reservoir fluid and rock data along with completion data revealed a good potential for waterflooding using closer spacing between the oil producer and the water injector fractures that forced the injected water to invade the hydraulic created fractures, natural fractures, and the reservoir matrix as well, which maximized the oil recovery. Collectively, our experimental and simulation study showed a good potential of waterflooding in Eagle Ford shale formation.
Determining Physical Properties of Unconventional Reservoir Rocks: from Laboratory Methods to Pore-Scale Modeling
Authors: Gerke Kirill M. , Vasilyev Roman V. , Korost Dmitry V. , Karsanina Marina V. , Balushkina Natalya S. , Khamidullin Ruslan , Kalmykov Georgy A. , Mallants Dirk 
Published: November 2013

Abstract
With the rapid progress of imaging methods it is now possible to obtain detailed rock structure information on different scales, ranging from nanometers to micrometers. Such knowledge facilitates use of pore-scale modeling approaches to predict numerous physical properties based on three dimensional structural data. Pore-scale modeling approaches can simulate different processes in the rock under natural conditions (pressure, temperature, etc.), which are more difficult to simulate in the laboratory. This is especially important for unconventional reservoir rocks such as the Bazhen formation siliceous rocks (black shales) used in this study. Based on X-ray microtomography and SEM imaging we develop a detailed categorization of different types of porosities (including micro, i.e. larger than µm size, and nano, i.e. sub-micron size, porosities) for samples of Bazhen siliceous rocks. Standard pore-scale modeling techniques do not account for different flow regimes within different pore sizes. Thus, we develop a pore-network model with different physics of gas flow for micro- and nanoporosity. High-resolution images are used for stochastic reconstructions of 3D structure and subsequently used for modeling of gas permeability. Resulting permeability values are in a good agreement with gas permeabilities measured for Bazhenov siliceous rocks. Finally, we present a framework to model gas permeability of unconventional reservoir rocks using multi-scale 3D structure information based on microCT scans and high resolution SEM/FIB-SEM imaging techniques.
Technical Aspects of Risking and Valuation of Shale Reservoirs
Authors: Ingsoy P. B. , Chandler A. S. , Lie O.. , Hashemi N.. 
Published: November 2013

Abstract
This paper focuses on valuation of shale based opportunities, arguing that the valuation process should be decision driven and model based, grounded in Bayesian principles. Risk should be controlled in order to maximize value. Using a decision tree to structure the valuation, we demonstrate that a method based on hypothesis testing can be utilized to determine the probabilities associated with chance nodes. It is shown that the probabilities depend on the scope and quality of the appraisal program. The risk level posterior to a chance node is discussed and calculated by Bayesian inversion. It is shown that the model underpinning the valuation must be updated posterior to chance nodes according to Bayes theorem. Failure to do so may lead to underestimating the value of the opportunity. Finally we discuss the use of simple truncation as an approximate method for updating the model after a pilot production phase.
A North American Review of Commercial Shale Plays; Have We Learned Anything Besides Serendipity?
Authors: Shelley R. F. , Mullen M. J. , Minner W. A. 
Published: November 2013

Abstract
When evaluating mud rock completions one is quickly struck with the complexity of the task. Mud rock "shales" by their very nature can be problematic to evaluate given the wide variation in geology, rock properties, and reservoir characteristics, not to mention the effect of multi-fractured horizontal well completions. Quite often, the reservoir characteristics between an economic well and an uneconomic well are very similar, further compounding the problem. So, what can we learn by taking another look at North American shale plays to help identify the more productive shales, improve economics and reduce the cycle time bringing this resource to market globally? Sometimes, the simple measurements we make at the wellsite can be very indicative of the things we don't measure very well, like the degree of natural fracturing and the interconnectedness of porosity. The subject material and the information discussed in this review was derived from the study of the characteristics and data from hundreds of completions with production results for shale wells in North America.
The findings presented show the results of formation evaluation and analytical evaluation which have proven to be good indicators of well productivity and hydrocarbon recovery. Many of these methods have been underutalized by the industry for shale evaluation and completion optimization.
Past successes in unconventional resource arenas are sometimes viewed as the result of seredipity. However, that has not been the case – past successes have evolved, in some cases over periods of years. A comparison of learnings from the Bakken and Eagle Ford show some interesting commonalities that help identify economic wells from subeconomic wells, as well as the most productive completion intervals in lateral wellbores. These findings and evaluation methodologies can readily contribute to the global hunt for unconventional reservoirs, and evaluation / optimization of their development strategy..
Calibrated Mechanical Earth Models Answer Questions on Hydraulic Fracture Containment and Wellbore Stability in Some of the CSG Wells in the Bowen Basin
Authors: Pallikathekathil Zachariah John , Puspitasari Ratih , Altaf Iftikhar , Alboub Mohamed , Mazumder Saikat , Sur Subhodip , Scott Michael , Kubenk David , Gan Thomas 
Published: November 2013

Abstract
The Coal Seam Gas (CSG) industry is currently focused on the large-scale development of a number of Liquefied Natural Gas (LNG) projects in Queensland, Australia. Arrow Energy is one of four proponents undertaking to develop such a project, with a focus on the Surat and Bowen basins. Arrow Energy also supplies gas to power stations, mineral refining facilities and ammonium nitrate plants in north Queensland. They are committed to maintaining the supply to these domestic customers and to the growing international gas market through the LNG project at Gladstone, Australia through its CSG projects.
The wells discussed in this paper are situated within Arrow Energy's tenements in the northern Bowen Basin. The targeted coal measures in the region usually occur at depths between 230m to 500m below the surface. A number of wells have been drilled in these coal measures and completed either by open-hole, horizontal drilling or, less frequently, hydraulic fracturing. To maximize the productivity, and thus success of these projects, there is a distinct need to understand the wellbore stability of horizontal wells as well as the potential for hydraulic fracture containment in the target formations.
Rigorous one-dimensional Mechanical Earth Models (1D MEMs) were constructed utilizing:
A complete suite of wireline logs, processed and interpreted for the purpose of construction of the models; Rock mechanics laboratory tests; Closure pressures obtained from Diagnostic Fracture Injection Tests (DFIT); Drilling-induced borehole failures when drilling the wells.
The 1D MEMs were constructed for utilizing data acquired specifically for the construction of the models. The models reveal the variation of maximum horizontal stress direction, coal properties in the various layers and contrast in stresses between the coal seams and inter-burden formations.
This paper presents the workflow used in the construction of the 1D MEMs for the CSG project applications, and the results obtained. The particular focus is on the following:
Data acquisition strategy (logs that were acquired for the construction of the 1D MEMs). Rock mechanics laboratory tests performed, the results obtained, and how these results were utilized in calibrating the 1D MEMs. Closure pressure estimates derived from well tests (DFITs), and how these results were utilized in calibrating the minimum horizontal stress. Borehole image log interpretation and characterization drilling-induced features (break out and drilling-induced fractures) that yield the direction of maximum horizontal stress and for calibrating the wellbore stability models. Predominant strike of fractures in the coal from advanced sonic tool.
Investigating Hydraulic Fracturing in Tight Gas Sand and Shale Gas Reservoirs in the Cooper Basin
Authors: Scott M. P. , Stephens T.. , Durant R. H. , McGowen J. M. , Thom W. W. , Woodroof R. A. 
Published: November 2013

Abstract
The majority of discoveries in the Cooper basin have been structural traps on regional highs, with significantly less information available from the deep tight sand and shale plays. Recently, exploration and appraisal of the large, prospective gas resources in the deep troughs began. While these plays have been known for some time (Hillis et al. 2001), data has only recently been presented detailing the unconventional targets in the Nappamerri trough (Pitkin et al. 2012). This paper focuses on unconventional reservoirs within the southern Cooper basin, specifically, a southern extension of the Nappamerri trough and the Mettika embayment, part of the Tenappera trough.
Senex Energy began to review the potential of the unconventional reservoirs in its Cooper basin acreage in 2010. This paper focuses on three wells, Skipton 1, Kingston Rule 1, and Hornet 1, which were hydraulically fractured in early 2013. In the well planning stage of the project, it was identified that sufficient data needed to be collected to characterize both the formation and hydraulic fracturing behavior. The requirement for fracturing diagnostics was critical because of the complex nature of hydraulic fracturing within the Cooper basin. To manage these unknowns, the data that were collected included core testing, diagnostic injection tests on most intervals, surface tiltmeters to measure fracture azimuth and orientation, radioactive (RA) tracers to infer fracture height, and chemical tracers to estimate the flowback contribution from each stage.
The results showed high treating pressures and near-wellbore pressure loss (NWBPL) in many stages of the fracture treatments. Generally, the lower the fracture gradient, the easier the job was to place and the better the reservoir quality. The RA tracers showed good containment in the one well in which they were used, with heights of 20 to 60 ft. The main barriers to height growth appeared to be changes in lithology. The surface tiltmeter results showed an azimuth that was different than expected from borehole breakout data in the basin. This has been seen in other studies in the Cooper basin. While the exact reason for this requires additional work, possible explanations are discussed within the paper.