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Collaborating Authors
Western Australia
Summary In some areas, seismic data can exhibit the effects of strong azimuthal anisotropy (AA). One of the major causes of AA can be anomalous horizontal stress regimes, which can be modeled as horizontally transverse isotropy (HTI). The Stybarrow field, located offshore NW Australia in the Carnarvon sedimentary basin, is one such area, where strong horizontal stress conditions have been present throughout the basin’s tectonic history. We find evidence for AA in repeat 3D seismic data acquired at two separate azimuths over the Stybarrow field. AA is observed in amplitude versus offset (AVO) reflection amplitude difference maps and cross plots, and is consistent with dipole shear logs and borehole breakout data in the area. We model azimuthal AVO responses using Ruger’s HTI AVO equation, using the anisotropy parameters derived from dipole shear logs, and compare the results with AVO data from the two 3D seismic surveys. Certain fault blocks (but not all) exhibit the same AAVO trend in the seismic data as those modeled from log data, consistent with a stress-induced HTI anisotropic model interpretation.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-32-L > Stybarrow Field > Macedon Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-255-P > Stybarrow Field > Macedon Formation (0.99)
SUMMARY The ability of the marine controlled source electromagnetic method to resolve anisotropy in the sediment conductivity is not very well understood. In this study, we address the resolvability of anisotropy using a Bayesian approach. Two markedly different methods, slice sampling and reversible jump Markov Chain Monte Carlo have been used for the Bayesian inversion of a synthetic model of a resistive oil reservoir trapped beneath the seabed. We use this to identify which components of data can provide the strongest constraints on anisotropy in the overburden, reservoir and underlying sediments.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Plateau > WA-1-R > Scarborough Field (0.99)
- Africa > South Africa > Western Cape Province > Indian Ocean > Bredasdorp Basin > Block 9 > EM Field (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (0.72)
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (0.72)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.56)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.49)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (0.55)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Uncertainty > Bayesian Inference (0.34)
- Information Technology > Artificial Intelligence > Machine Learning > Learning Graphical Models > Directed Networks > Bayesian Learning (0.34)
Summary Uncertainties in marine controlled source electromagnetic (CSEM) data consist of two independent parts: measurement noise and position uncertainties. Measurement noise can be readily determined using stacking statistics in the Fourier domain. The uncertainties due to errors in position can be estimated using perturbation analysis given estimates of the uncertainties in transmitter-receiver geometries. However, the various geometric parameters are not independent (e.g. change in antenna dip affects antenna altitude, etc.) so how uncertainties derived from perturbation analysis can be combined to derive error-bars on CSEM data is not obvious. In this study, we use data from the 2009 survey of the Scarborough gas field to demonstrate that (a) a repeat tow may be used to quantify uncertainties from geometry, (b) perturbation analysis also yields a good estimate of data uncertainties as a function of range and frequency so long as the components are added arithmetically rather than in quadrature, and (c) lack of a complex error structure in inversion yields model results which are unrealistic and leads to "over-selling" of the capabilities of CSEM at any particular prospect.
Explorers are moving to increase the “discovery space” by exploring under cover and to greater depths, e.g., subsalt and sub-basalt exploration for oil and gas, and beneath transported cover for minerals. With this shift, there becomes an increased reliance on geophysical methods to delineate resources with no recognized geological or geochemical expressions. Different geophysical fields provide information about different physical properties of the Earth. Multiple geophysical surveys spanning gravity, magnetic, electromagnetic, and seismic methods are often interpreted to infer geology from models of different physical properties. In many cases, the various geophysical data are complementary, making it natural to consider a formal mathematical framework for their joint inversion to a shared Earth model. There are different approaches to joint inversion. The simplest case of joint inversion is where the physical properties are identical between different geophysical methods (e.g., Jupp and Vozoff, 1975). In other cases, joint inversion may infer theoretical, empirical, or statistical correlations between different physical properties (e.g., Hoversten et al., 2003, 2006). In cases where the physical properties are not correlated but, nevertheless, can be assumed to share a similar structure, joint inversions have been formulated as a minimization of the cross-gradients between different physical properties (e.g., Haber and Oldenburg, 1997; Gallardo and Meju, 2003, 2004). The latter has now been widely adopted by joint inversion practitioners as the de facto standard (e.g., Colombo and De Stefano, 2007; Hu et al., 2009; Jegen et al., 2009; De Stefano et al., 2011).
- Geology > Rock Type > Igneous Rock (0.90)
- Geology > Mineral > Native Element Mineral > Gold (0.47)
- Geology > Mineral > Oxide > Iron Oxide (0.33)
- Geophysics > Magnetic Surveying (1.00)
- Geophysics > Gravity Surveying (1.00)
- Geophysics > Electromagnetic Surveying (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.46)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Oceania > Australia > Western Australia > Canning Basin > Block EP EP 390 > Olympic Field > Nita Formation (0.94)
- Oceania > Australia > Western Australia > Canning Basin > Block EP EP 390 > Olympic Field > Acacia Formation (0.94)
- Oceania > Australia > Western Australia > Canning Basin > Block EP 473 > Olympic Field > Nita Formation (0.94)
- (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...)
Developing a Predictor for Degradation of High Strength Corrodible Tripping Balls used in Multi-Zone Fracturing Treatments in Unconventional Hydrocarbon Reservoirs
Carrejo, Nick (Baker Hughes Inc.) | Mathur, Vipul (Baker Hughes Inc.) | Mazyar, Oleg A. (Baker Hughes Inc.) | Gaudette, Sean (Baker Hughes Inc.)
Abstract Multi-point hydraulic fracturing in unconventional hydrocarbon-bearing shale reservoirs has proven to greatly enhance production economics. Recent technology has allowed for as many as 40 individual fracture points. Tripping balls are a major component of these multi-point fracturing systems and are used to actuate fracturing sleeves to pinpoint fracture initiation and placement. While seated on ball seats, the tripping balls may experience pressures approaching 10,000psi. However, following a successful formation fracture, the tripping balls may hinder production. Potential problems relate to the tripping balls becoming stuck on the fracturing seats. Tripping balls remaining in the lateral can also lead to problems if wellbore re-entry is required. These production risks can lead to significantly increased costs and potential lost production. A new, high-strength corrodible material has been developed for tripping balls to alleviate potential problems in these unconventional reservoirs. This material has yielded an interventionless means of flow assurance. The mechanical properties and degradation rates of these newly engineered materials have been investigated to determine the downhole characteristics. The characterization results of these materials are discussed in an effort to develop a method for accurately predicting the timeframe in which these high-strength corrodible tripping balls fully degrade, and thus eliminate possible production risks. The testing included investigations of the degradation rates of these materials in brines, and at various temperatures. Materials were also pressure tested on multiple ball seat configurations used in the multi-zone fracturing systems1.
- North America > Mexico (0.28)
- North America > Canada (0.28)
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)
Abstract The Pyrenees Development comprises three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin and are operated by BHP Billiton (Fig. 1). Eighteen subsea wells, including 14 horizontal producers, 3 vertical water disposal wells and 1 gas injection well have been constructed to date and additional wells are planned for infill and to develop additional resources. First oil was achieved during February 2010 and production exceeded 50 million barrels in November 2011. Figure 1: Pyrenees Development Location Map The Pyrenees fields are low relief, with oil columns of approximately 40 metres within excellent quality reservoirs of the Barrow Group. The 19° API crude has moderate viscosity, low gas / oil ratio (GOR), and a strong emulsion forming tendency which makes oil/water separation and accurate well test metering difficult. Early in the project design phase it was identified that the complex subsea gathering system and the need to reduce measurement uncertainties would dictate special attention to production measurement. Subsea multiphase flow meters (MPFMs) were specified to meet the challenges of production optimization and allocation while at the same time minimizing production deferral for separator testing. Each oil producer is monitored by a dedicated MPFM. With 14 meters, Pyrenees is among the largest subsea MPFM installations worldwide. This paper describes the process of MPFM qualification and commissioning together with their performance over 2 years in the field. We show how close cooperation between the Operator and MPFM Vendor has enabled quality rate measurements of emulsified production despite large changes in producing gas/oil ratio and water cut. While the primary justification for Pyrenees subsea MPFMs was production allocation and optimization, interpretation of transient water cut and GOR data proved valuable for production and reservoir engineering applications. Examples of proactive reservoir and production management including optimizing drawdown of Inflow Control Device (ICD) equipped wells, optimizing well lineup and gas lift to commingled wells are presented.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-43-L > Block WA-43-L > Pyrenees Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-43-L > Block WA-42-L > Pyrenees Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-43-L > Block WA-12-R > Pyrenees Field (0.99)
- (19 more...)