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Summary Geoscience techniques that are well established for conventional oil and gas exploration and production are equally applicable to shale gas systems. A robust data set allowed lithostratigraphic classifications and reservoir characterizations to be carried out in the Horn River Basin of northeast British Columbia. When it was demonstrated that statistical relationships existed between the lithostratigraphic classifications and elastic rock properties it became possible to invert 3D seismic volumes for the elastic properties and map the lithostratigraphic units by directly applying the statistical relationships. These findings for lithostratigraphic classifications are also applicable to key shale gas reservoir properties such as porosity or total organic carbon. From these transformations it was straightforward to apply standard data-reduction and mapping processes to determine quantities needed for key project decisions such as pad design and land acquisition rankings.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.89)
- Geology > Geological Subdiscipline > Stratigraphy > Lithostratigraphy (0.87)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (7 more...)
Abstract The amount of tight formations petrophysical work conducted at present in horizontal wells and the examples available in the literature are limited to only those wells that have complete data sets. This is very important. But the reality is that in the vast majority of horizontal wells the data required for detailed analyses are quite scarce. To try to alleviate this problem, a new method is presented for complete petrophysical evaluation based on information that can be extracted from drill cuttings in the absence of well logs. The cuttings data include porosity and permeability. The gamma ray (GR) and any other logs, if available, can help support the interpretation. However, the methodology is built strictly on data extracted from cuttings and can be used for horizontal, slanted and vertical wells. The method is illustrated with the use of a tight gas formation in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). However, it also has direct application in the case of liquids. The method is shown to be a powerful petrophysical tool as it allows quantitative evaluation of water saturation, pore throat aperture, capillary pressure, flow units, porosity (or cementation) exponent m, true formation resistivity, distance to a water table (if present), and to distinguish the contributions from viscous and diffusion-like flow in tight gas formations. The method further allows the construction of Pickett plots without previous availability of well logs. The method assumes the existence of intervals at irreducible water saturation, which is the case of many tight formations currently under exploitation. It is concluded that drill cuttings are a powerful direct source of information that allows complete and practical evaluation of tight reservoirs where well logs are scarce. The uniqueness and practicality of this quantitative procedure is that it starts from only laboratory analysis of drill cuttings, something that has not been done in the past.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.30)
- Oceania > Australia > Western Australia > Perth Basin (0.99)
- North America > United States > Colorado > Spindle Field (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (17 more...)
Abstract Microfrac or fall off injection test is a technique used to accurately measure minimum horizontal stress directly in the formation. However, other than being expensive and time consuming, this test does not give a continuous minimum horizontal stress profile. Continuous minimum horizontal stress profile is especially important for hydraulic fracturing design for the tight Montney formation. This study utilizes logging data and core reports to generate the minimum horizontal stress profile for two Montney wells in North East British Columbia. Specific value of tectonic stress determined from injection fall off analysis is also included in the calculation. The first method, conventional method, calculates minimum horizontal stress by solving linear poroelasticity equations with vertical stress equal to the overburden. Closure pressure from fall-off injection test is used as a calibration point to acquire tectonic stress. The second method incorporates the tectonic, thermal effect and rock mechanical properties at each incremental depth to generate the minimum horizontal stress. The third method, vertical transverse isotropy (VTI), is conducted assuming different rock properties on the vertical and horizontal direction and also different tectonic strain for the maximum and minimum direction. The conventional method yields the lowest minimum horizontal stress magnitude without any distinctive characteristic. On several zones, the VTI method shows higher stress magnitude above Montney and reveals some good zone containment for hydraulic fracturing design, which the conventional method does not provide. From the injection fall off analysis, a second closure pressure with lower value than the first closure is believed to represent the overburden stress. It is concluded that this area has a thrust fault regime in which overburden stress is the least principle stress.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.79)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.48)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Mississippi > Travis Peak Formation (0.99)
- North America > United States > Louisiana > Travis Peak Formation (0.99)
- (7 more...)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Canadian Unconventional Resources Conference held in Calgary, Alberta, Canada, 30 October-1 November 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract mus t contain conspicuous acknowledgment of SPE copyright. Abstract This paper presents a methodology for connecting geology, hydraulic fracturing, economics, environment and the global natural gas endowment in conventional, tight, shale and coalbed methane (CBM) reservoirs. The volumetric estimates are generated by a variable shape distribution model (VSD). The VSD has been shown in the past to be useful for the evaluation of conventional and tight gas reservoirs. However, this is the first paper in which the method is used to also include shale gas and CBM formations.. Results indicate a total gas endowment of 70000 tcf, split between 15000 tcf in conventional reservoirs, 15000 tcf in tight gas, 30000 tcf in shale gas and 10000 tcf in CBM reservoirs. Thus, natural gas formations have potential to provide a significant contribution to global energy demand estimated at approximately 790 quads by 2035. A common thread between unconventional formations is that nearly all of them must be hydraulically fractured to attain commercial production. A significant volume of data indicates that the probabilities of hydraulic fracturing (fracking) fluids and/or methane contaminating ground water through the hydraulically-created fractures are very low. Since fracking has also raised questions about the economic viability of producing unconventional gas in some parts of the world, supply cost curves are estimated in this paper for the global gas portfolio.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (0.93)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.34)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.70)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.46)
- Geophysics > Borehole Geophysics (0.46)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Oceania > Australia > Western Australia > Perth Basin (0.99)
- North America > United States > Wyoming > Sand Wash Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- (35 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
Abstract Fracture fluid flow back has been identified as one of the major challenges of hydraulic fracturing operations conducted in shale reservoirs. Factors causing the very low fracture fluid recovery need to be well understood and properly addressed, in order to get full benefits from costly hydraulic fracture jobs conducted in unconventional reservoirs. Despite the recent surge of investigations of the problem, one major question still remains: what happens to the fracture fluid that is not recovered? Does it stay in the fracture or does it go into the matrix? In case of both mechanisms are responsible for fracture fluid retainment, what fraction of fracture fluid stays in the propped fracture and what fraction is transferred from fracture to matrix. The focus of the current study is to understand if the transfer of fracture fluid from fracture to matrix through imbibition is of significant importance. We systematically measure the imbibition rate of water, brine, and oil into the actual core samples from the three shale sections of Horn River basin (i.e., Fort Simpson, Muskwa and Otter Park). We characterize the shale samples by measuring, porosity, wettability, mineral composition through XRD analysis, and interpreting the well log data. The results show that imbibition could be a viable mechanism for fluid transfer from fracture to matrix in Horn River shales. The comparative study shows the imbibition rate in the direction parallel to the bedding plane is higher than that in the direction perpendicular to the bedding. The study also suggests that the imbibition rate of the aqueous phases is significantly higher than that of the oleic phases.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Northwest Territories > Fort Simpson (0.29)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
Systematic Evaluation of Unconventional Resource Plays Using a New Play-Based Exploration Methodology
Neber, Alexander (Schlumberger) | Cox, Stephanie (Schlumberger) | Levy, Tom (Schlumberger) | Schenk, Oliver (Schlumberger) | Tessen, Nicky (Schlumberger) | Wygrala, Bjorn (Schlumberger) | Bryant, Ian (Schlumberger)
Abstract New tools are now available to provide a rigorous and systematic play-based exploration approach to the evaluation of unconventional resources. Coupled with petroleum system modeling, this methodology offers an efficient and effective approach to identify "sweet spots" early in the life of resource plays. Petroleum system modeling can be applied to predict the type and quantity of hydrocarbon in shale formations, as well as the proportion of adsorbed gas and geomechanical properties that are important for hydraulic fracture stimulation of shale reservoirs. Maps of these properties are then converted to chance-of-success maps for hydrocarbon generation, retention, and pore volume that can be integrated with nongeological factors, such as access and drilling depth required to reach target reservoirs. These play-based maps are expressed in probability units, so simple map multiplication provides a map of the play's overall chance of success, delineating the sweet spots. A similar methodology is applicable to evaluation of coalbed methane resources. In this paper, we illustrate this methodology using examples from shale oil and gas shale plays in North America. These include data-rich plays from the North Slope of Alaska and data-poor plays from the northeastern and southern regions of the United States, which are more representative of many Asia-Pacific basins. We show how predictions from petroleum system modeling based on sparse data provide a good match with results of subsequent development drilling and production. Petroleum system-based assessment of resources in place, combined with an assessment of overall play risk, enables companies to make decisions on acquisition of acreage early in the life of unconventional resource plays based on the probability of them containing economically viable resources.
- Oceania > Australia (1.00)
- North America > United States > West Virginia (1.00)
- North America > United States > Texas (1.00)
- (4 more...)
- Phanerozoic > Mesozoic (1.00)
- Phanerozoic > Paleozoic > Devonian (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.90)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.96)
- Oceania > Australia > Western Australia > Perth Basin > Carynginia Shale Formation (0.99)
- Oceania > Australia > Northern Territory > Georgina Basin > Arthur Creek Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (52 more...)
Abstract Thermal maturity is an important parameter for commercial gas production from gas shale reservoirs if the shale has considerable organic content. There is a common idea that gas shale formations with higher potential for gas production are at higher thermal maturity status. Therefore estimating this parameter is very important for gas shale evaluation. The present study proposes an index for determining thermal maturity of the gas shale layers using the conventional well log data. To approach this objective, different conventional well logs were studied and neutron porosity, density and volumetric photoelectric adsorption were selected as the most proper inputs for defining a log derived maturity index (LMI). LMI considers the effects of thermal maturity on the mentioned well logs and applies these effects for modelling thermal maturity changes. The proposed methodology has been applied to estimate thermal maturity for Kockatea Shale and Carynginia Formation of the Northern Perth Basin, Western Australia. A total number of ninety eight geochemical data points from seven wells were used for calibrating with well log data. Although there are some limitations for LMI but generally it can give a good in-situ estimation of thermal maturity.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Oceania > Australia > Western Australia > Perth Basin > Northern Perth Basin (0.99)
- Oceania > Australia > Western Australia > Perth Basin > Kockatea Shale Formation (0.99)
- Oceania > Australia > Western Australia > Perth Basin > Carynginia Shale Formation (0.99)
- (13 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
Characterization of Critical Fluid, Rock, and Rock-Fluid Properties-Impact on Reservoir Performance of Liquid-rich Shales
Honarpour, M. M. (Hess Corporation, Houston, Texas) | Nagarajan, N. R. (Hess Corporation, Houston, Texas) | Orangi, A.. (Maersk Oil Company, Qatar) | Arasteh, F.. (Hess Corporation, Houston, Texas) | Yao, Z.. (Hess Corporation, Houston, Texas)
Abstract Liquid-rich Shale (LRS) reservoirs are economically attractive but operationally challenging. Fluid, rock, and rock-fluid properties are critical for optimal reservoir development and management. Formation heterogeneity, fluid variability, and complexity of rock-fluid properties render fluid flow characterization a challenging task. Additional challenges associated with coring, fluid sampling and analysis include the recovery of quality cores and representative fluid samples, and timely acquisition of high quality data for making critical engineering design decisions. Rock and fluid analyses should be done in the following stages so that the critical data become available in a timely manner for making key decisions: a)‘Wellsite Analysis’ including mineralogy/total organic content, TOC; b)‘Quick Look laboratory analysis’ for detailed mineralogy and basic petrophysical properties; c)‘Fast Track’ geomechanical, geochemical properties and petrophysical analysis on core plugs; and d)‘Full Suite’ rock-fluid analysis for integrated studies. Low formation permeability, long transients, and contamination with OBM and fracturing fluid make acquisition of representative downhole or early surface fluid samples impractical. An alternative approach is to integrate mud gas analysis with light and heavy end components extracted from full diameter cores in canisters to reconstruct in-situ fluids. The PVT modeling should account for the impact of high capillary pressures encountered in unconventional shale reservoirs for reliable reservoir performance prediction. This paper presents the best practice methodology for characterizing critical rock and fluid properties, their variability and their impact on performance through parametric simulation studies. A sector model was constructed consisting of alternate TOC- and calcite-rich layers with a horizontal well placed in a calcite-rich layer. A network of hydraulic and natural fractures was implemented in the model to study the sensitivities to fluid and rock properties, relative permeability, capillary pressure, and fracture properties. It was found that the critical rock and fluid data impacting the initial rate and ultimate recovery were effective permeability, its anisotropy, its alignment with hydraulic and natural fracture network, rock-type based compaction, unconventional PVT behavior such as decreased oil bubble point pressure and the resultant viscosity and GOR behavior, interfacial tension (IFT)/capillary pressure, and relative permeability.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Roebuck Basin > Bedout Basin > Milne Sandstone Formation (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Roebuck Basin > Bedout Basin > Baxter Sandstone Formation (0.98)
Abstract In late 2011 the Queensland State Government of Australia declared the Cooper Creek Basin in South West Queensland to be a Wild River Area under the Wild River Act 2005. The Wild River Area covers a significant proportion of Santos’ current tenements and future development interests in the area. The Wild Rivers Declaration is a highly prescriptive regulatory regime that sets out significant restrictions which would detrimentally impact on existing operations and future oil and gas development opportunities, including emerging coal seam and shale gas prospects in the proposed declaration area. It includes general prohibitions on certain activities across extensive areas of channel country and the imposition of setbacks for activities in proximity to watercourses. The issue first arose in late 2010 when the Queensland Government indicated its intent to declare the Cooper Creek Basin as a Wild River through its issue of a Declaration Proposal. During the 12 month consultation period that followed, Santos engaged with the Queensland Government regulators and Ministers to assist the Government to make a Wild Rivers Declaration that achieves a balance between protecting the natural values of the Cooper Creek and allowing the continuation of the sustainable development of the petroleum resources within the Cooper and Eromanga Basins. The paper will provide insight into Santos’ experience in taking a lead role in responding to the significant new legislative regime proposed by Government. Key insights include the need for industry tobe proactive and take a role in educating the Government on the industry's operations andthe changes required to ensure compliance with the new regulatory requirements. It will also discuss broadlythe challenges associated with the changing regulatory environment including the role that politics can play and observes that we should continue to expect a ‘Wild’ ride whenparticipating in thelegislative developmentprocess. The significance of the Declaration is that the restrictions for petroleum activities imposed in the Cooper Creek Basin Wild Rivers Declaration may be imposed upon all Wild Rivers areas in Queensland. In addition, other Australian state governments are watching the implementation of Wild Rivers’ legislation in Queensland and are considering the need for similar regulatory regimes in their jurisdictions.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Oceania Government > Australia Government > Queensland Government (0.55)
- Oceania > Australia > Western Australia > Great Australian Bight > Bight Basin > Eyre Basin (0.99)
- Oceania > Australia > South Australia > Cooper Eromanga Basin (0.98)
- Oceania > Australia > Queensland > Cooper Eromanga Basin (0.98)
- (31 more...)
1. INTRODUCTION Consideration of the 3D anisotropy of rocks has become a more common oilfield reservoir characterization practice today, particularly in unconventional shale reservoirs. In the past, rocks were commonly described with isotropic properties, simplifying the second order stiffness tensor into two dynamic properties (DTc and DTs) and the compliance rock tensor into two independent elastic properties such as Young’s modulus and Poisson’s ratio. Sometimes the isotropy assumption was considered, even though a great difference between vertical and horizontal rock stiffness was obvious from acoustic logs or ultrasonic core measurements. Sedimentary rocks frequently are anisotropic by nature due to lamination, bedding and in some cases due to micro-cracks or natural fractures. Shales, in particular, are strongly anisotropic, not only transversely between vertical and horizontal elastic properties but azimuthally when they contain aligned micro-cracks or macroscopic natural fractures. Therefore, accurate in-situ horizontal stress profiles in shales require a full orthotropic anisotropic model. This paper provides an analytical solution for the two horizontal stresses as a function of the stiffness tensor components and the relationship between the orthotropic elastic pro stiffness tensor. Currently, cross-dipole multi-array acoustic logs are available to measure shear wave anisotropy in rocks from vertical wells. The azimuthally polarized vertical shear wave anisotropy can be estimated from cross-dipule full-wave forms while the transverse shear wave anisotropy can be derived from Stoneley wave monopole processing. However, these two acoustic anisotropies still provide insufficient information to fully describe orthotropic rocks. Consequently, additional acoustic measurements performed on core samples complement the information and enable full characterization of the stiffness tensor. A vertically transverse isotropic rock requires five independent elastic measurements while an orthotropic rock needs nine elastic constants. Sensitivity analyses are presented to demonstrate the influence of rock anisotropy in deriving horizontal stresses for three cases: isotropic, transverse isotropic and fully orthotropic.
- North America > United States > Texas (0.93)
- Asia (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.68)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.68)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)