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Collaborating Authors
Western Australia
A Variable Shape Distribution (VSD) Model for Characterization of Pore Throat Radii, Drill Cuttings, Fracture Apertures and Petrophysical Properties in Tight, Shale and Conventional Reservoirs
Aguilera, Roberto F. (Center for Research in Energy and Mineral Economics (CREME), Curtin University) | Ramirez, John Freddy (Schulich School of Engineering, University of Calgary) | Ortega, Camilo (Schulich School of Engineering, University of Calgary) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract Fractal and power law distributions have been found in the past to be useful for modeling some reservoir properties following the assumptions of constant shape and self-similarity. This study shows, however, that pore throat apertures, fracture apertures, petrophysical and drill cuttings properties of unconventional formations are better matched with a variable shape distribution model (as opposed to constant shape). This permits better reservoir characterization and forecasting of reservoir performance. Pore throat apertures, fracture apertures, petrophysical properties and drill cutting sizes from tight and shale reservoirs are shown to follow trends that match the variable shape distribution model (VSD) with coefficients of determination (R) that are generally larger than 0.99. The good fit of the actual data with the VSD allows more rigorous characterization of these properties for use in mathematical models. Data that could not be described previously by a single equation can now be matched uniquely by the VSD. Examples are presented using data from conventional, tight and shale formations found in Canada, the United States, China, Mexico and Australia. In addition, the study shows that the size of cuttings drilled in vertical and horizontal wells can also be matched with the VSD. This allows the use of drill cuttings, an important direct source of information, for quantitative evaluation of reservoir and rock mechanics properties. The results can be used for improved design of stimulation jobs including multi stage hydraulic fracturing in horizontal wells. This is important as the amount of information collected in horizontal wells drilled through out tight formations, including cores and well logs, is limited in most cases. It is concluded that the VSD is a valuable tool that has significant potential for applications in conventional, low and ultra-low permeability formations and for evaluating distribution of rock properties at the micro and nano-scale.
- Asia (1.00)
- North America > Canada > Alberta (0.70)
- North America > Canada > Quebec (0.46)
- North America > United States > California (0.46)
- Research Report > Experimental Study (0.88)
- Research Report > New Finding (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Oceania > Australia > Western Australia > Perth Basin (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Quebec > Appalachian Basin > Utica Shale Formation (0.99)
- (9 more...)
Abstract The Stybarrow Field is a moderately sized biodegraded 22° API oil accumulation reservoired in Early Cretaceous sandstones of the Macedon Formation in the Exmouth Sub-Basin, offshore Western Australia. The reservoir is comprised of excellent quality, poorly consolidated turbidite sandstones up to 20m thick. The field lies in approximately 800m of water and has been developed with five near-horizontal producers and three water injection wells. The Stybarrow development came online at an initial rate of 80,000BOPD in November 2007. Due to the lack of significant aquifer support, water injection was planned from start-up for pressure maintenance. Acquisition of a variety of data types have enabled key subsurface challenges to be addressed both before and during production. Structural and stratigraphic complexities influence connectivity and therefore must be fully evaluated in order to achieve optimal sweep. A feasibility study concluded that Stybarrow would be a good candidate for 4D seismic monitoring. Two monitor surveys were acquired and, along with other reservoir surveillance techniques, have been used to refine the geological model. The first monitor survey at Stybarrow was recorded in November 2008. The results of this survey were in agreement with prior 4D modelling and supported the drilling of a successful development well in the north of the field. A second monitor survey was recorded in May 2011, three and a half years after first oil and at 70% of expected ultimate recovery. This survey is currently being analysed to determine if sweep patterns have changed. The 4D surveys have proven to be an important tool for understanding subsurface architecture and dynamic fluid-flow behaviour. The results of both 4D seismic surveys have provided significant contributions to understanding the dynamic behaviour within the reservoir to facilitate optimal reservoir management.
- Research Report > New Finding (0.66)
- Overview (0.54)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.56)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Macae Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Lago Feia Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-255-P > Stybarrow Field > Macedon Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract Cleanup operations of gas wells are conducted when the well is kicked off and tested the first time. During cleanup, the drilling and completion fluids come out of the well along with the produced gas and associated liquids. The phenomena is transient in nature and minimum gas rate and time required for cleanup are key questions to be answered before embarking on the cleanup and subsequent well test operation. The knowledge of minimum gas rate and time required for cleanup can assist the engineer in deciding the well test package and make best use of the available time. In the current study, transient simulations of cleanup and MRT of three horizontal gas wells are conducted using a commercial multiphase transient simulator. Before the actual cleanup operations, simulations were conducted to estimate the cleanup time and to arrive at optimum beanup procedure to achieve best cleanup for a maximum gas rate constraint of 60 MMscf/D which is dictated by the size of well test package. After the cleanup and MRT operations were conducted, the operational data was used to tune the model. It was observed that the predicted temporal variations of gas rate and gauge temperature and pressure from the tuned model were in very good agreement with the measured values. The tuned model was then used to ascertain the degree of cleanup achieved from the actual cleanup and MRT operations and the model predictions showed that except the last 60 metres from the toe, the wells were completely cleaned of completion fluid. The poor cleanup in the last 60 metres was possibly because of 60 MMscf/D gas rate limit imposed by the size of well test package or resulting from poor contribution from the near-toe area. The study brings forth the significance of dynamic simulations in predicting and history matching gas well clean up operations and how dynamic simulations can provide an insight into the pressure and flow transients during cleanup. The knowledge gained from dynamic simulations can assist the engineer in deciding the well test package for gas wells to be cleaned up and in quantifying the cleanup achieved from an already conducted cleanup operation.
- North America > United States (0.93)
- Oceania > Australia > Western Australia (0.28)
- 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)
- (56 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract The first hydraulically operated completion was installed in Australia in 2004 (Guatelli et al 2004). Since then, a number of intelligent completions have been installed in offshore Australia. The remoteness of offshore Australia, particularly in the Timor Sea area, means intervention vessels are not readily available and well interventions are costly operations. For this reason, intelligent completion is considered to be an attractive alternative, by providing a down-hole solution to actively manage the reservoir production life and delay potential water breakthrough. The Kitan oil field is remotely located in the Joint Petroleum Development Area (JPDA) between East Timor and Australia. The Kitan oil field production facilities consist of three vertical producing wells, subsea flowlines, risers, and one Floating Production Storage and Offloading (FPSO) facility. The wells were completed with an intelligent design and cleaned up using a rig before the FPSO arrived on location. The intelligent completion design consists of two multi-stage hydraulic down-hole Flow Control Valves (FCVs) and three Down-Hole Gauges (DHGs) to independently control and monitor two different production zones. The FCVs have a total of 8 positions (fully opened, fully closed and 6 intermediate choke positions). It is planned to close the lower FCV to shut off water production from the lower zone while the upper FCV remains fully opened over the field life. The different FCV choke positions were utilized during the field startup and during the early stages of production while the water cut was still low, to overcome unforeseen technical limitations in the production system, and to optimize hydrocarbon production. This paper describes various aspects of the Kitan oil field intelligent well completion from design through installation and field startup to early stage of production operations, and includes technical problems encountered during the field startup as well as lessons learnt.
- Oceania > Timor-Leste > Timor Sea > Bonaparte Basin > Kitan Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Browse Basin > Block WA-315-P > Plover Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Browse Basin > Block WA-274-P > Plover Formation (0.99)
- Oceania > Australia > Timor Sea > Bonaparte Basin > Kitan Field (0.99)
Successful Application of Well Inflow Tracers for Water Breakthrough Surveillance in the Pyrenees Development, Offshore Western Australia
Napalowski, Ralf (BHP Billiton Petroleum) | Loro, Richard (BHP Billiton Petroleum) | Anderson, Calan (BHP Billiton Petroleum) | Andresen, Christian (RESMAN) | Dyrli, Anne Dalager (RESMAN) | Nyhavn, Fridtjof (RESMAN)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Asia Pacific Oil and Gas Conference and Exhibition held in Perth, Australia, 22-24 October 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 must contain conspicuous acknowledgment of SPE copyright.
- 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)
- (17 more...)
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)
Phase Trapping Damage in Use of Water-Based and Oil-Based Drilling Fluids in Tight Gas Reservoirs
Bahrami, Hassan (Curtin University) | Rezaee, Reza (Curtin University) | Saeedi, Ali (Curtin University) | Murickan, Geeno (Curtin University) | Tsar, Mitchel (Curtin University) | Mehmood, Sultan (Curtin University) | Jamili, Ahmad (University of Oklahoma)
Abstract Low matrix permeability and significant damage mechanisms are the main signatures of tight gas reservoirs. During drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around wellbore and eventually reduces permeability at near wellbore. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves. Water blocking and phase trapping damage is one of the main concerns in use of water based drilling fluid in tight gas reservoirs, since due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formations may result in introduction of an immiscible liquid hydrocarbon drilling or completion fluid around wellbore, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. This study focuses on phase trapping damage caused by liquid invasion using water-based drilling fluid in comparison with use of oil-based drilling fluid in water sensitive tight gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and results of laboratory experiments core flooding tests in a West Australian tight gas reservoir are shown in which the effect of water injection and oil injection on the damage of core permeability are studied. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of reducing skin factor and improving well productivity.
- North America > United States (0.94)
- Asia (0.68)
- North America > Canada > Alberta (0.28)
- (2 more...)
Design, Qualification, and Installation of Openhole Gravel Packs: Mari B Field, Offshore Israel
Healy, John (Noble Energy) | Sanford, Jack (Noble Energy) | Reeves, Donald (Noble Energy) | Dufrene, Kerby (formerly with Schlumberger) | Luyster, Mark (M-I SWACO) | Offenbacher, Matt (M-I SWACO) | Ezeigbo, Eze (M-I SWACO)
Abstract A case history from Offshore Israel is presented that describes the successful delivery of two ultra high-rate gas wells (>200 MMscf/D) completed in a depleted gas reservoir with 9⅝-in. production tubing and an openhole gravel pack (OHGP). Maximizing gas off-take rates from a volumetric drive gas reservoir that possesses high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of wells completed with 9⅝-in. production tubing ("big bore") determined that this design concept was feasible and deliverable in a short time frame while still maintaining engineering rigor. The paper will highlight key accomplishments within various phases of a completion delivery process with particular emphasis on the sand control design, testing and execution. The completions were installed with minimal issues (NPT ≈ 9%) and have produced without incident. The two wells, Mari-B #9 and #10, achieved a peak gas rate of 223 and 246 MMscf/D, respectively.
- Asia > Middle East > Israel (0.70)
- North America > United States > California (0.46)
- 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)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > South East Galeota Block > Cannonball Field (0.99)
- (6 more...)
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)