The commom occurrence of massive methane hydrate in numerous gas chimney structures, located in Joetsu basin, Sea of Japan, stimulates great interest from by academia, industry and national institutes in developing technologies to produce the potential energy resource. Unlike other deep methane hydrate deposited in formations a few hundred meters below seafloor, the hydrate chimney structures are located at the seafloor or up to 100 m below the seafloor; therefore, previously field-tested production methods such as depressurization are not applicable. The newer production method of jetting from the openhole section of a wellbore to excavate the hydrate bearing formation was proposed as a possible production method. However, jetting will create large empty chambers below the seafloor and could possibly jeopardize the stability and safety of well-heads and the production facility on the seafloor.
This paper presents a 3D geomechanical simulation study to evaluate the feasibility of the jetting method to produce methane from the hydrate chimneys in the Sea of Japan. In this study, to honor lateral and vertical variation of hydrate saturation as well as mechanical properties, different 3D geomechanical models were constructed to represent three shallow methane hydrate inhabitation types (chunk, laminated, and dispersed) by using data from various sources. Dynamic numerical simulation by using a 3D finite element simulator was conducted to simulate the jetting process to excavate 16-m diameter chamber from bottom of the borehole (about 100 m below seafloor) progressively up to the bottom of the conductor of the wellbore, about 10-m below the seafloor.
The numerical simulation shows that jetting is likely to be feasible as all simulation cases resulted in tolerable vertical displacement and equivalent plastic strain under ideal conditions, e.g., lateral homogeneous formation, constant chamber pressure (equal to formation pore pressure) and blowout preventer (BOP) weight of 20 t. In these cases, the plastic zone only extends to limited area from the sidewall. Additional complexities were considered in the numerical simulation to evaluate the operational risks during actual jetting operations, such as faulting, fluctuation of chamber pressure, and change of BOP weights.
This numerical simulation evaluated potential risks related to jetting operations of hydrate chimneys in the Sea of Japan and provided critical information for the engineering design of the proposed field test of jetting operations to produce this valuable resource in the Sea of Japan.
The focus of this study is to improve our technical understanding of anticipated drilling hazards in the Arctic Circle, especially hazards relating to drilling into and adjacent to evaporitic (salt) structures and associated tectonics. We explore current drilling technologies available to us to mitigate any anticipated drilling hazard. We demonstrate applicable operational experiences from other areas similar to drilling in the Arctic.
The Arctic's vast oil and gas potential has spurred exploration since mid-20th century. Government institutions such as the Geological Survey of Canada and historic companies such as Panarctic provide critical information on geology and petroleum discoveries. U.S. Geological Survey (2008) published Arctic mean estimated undiscovered technically recoverable conventional oil and gas resources at a total of 412 billion barrels of oil equivalent (BBOE).
Exploration in the Arctic varies in complexity mainly based on the depth drilled and hazards encountered. The remoteness of drilling anywhere in the Arctic makes both onshore and offshore operations generally more complex than drilling elsewhere in the world. To put it in perspective, our research into drilling time in deepwater Nova Scotia show for the majority of high complexity wells, non-productive time (NPT) can exceed 24% of total drilling time, and half of documented NPT is contributed to formation related problems.
Our geological analysis has found that Arctic petroleum basins and margins such as the Sverdrup Basin and East Canada and show comparable salt tectonics to Nova Scotian continental margin, offshore Brazil and Angola. Salt diapirs, salt domes, and thicken salt sections are common occurrences. Associate structures such as anticlines, extensional growth faults, wrench faults are observed in these basins. Extensional growth faults, listric normal faults, thrust faults, flank-salt shears, and brecciated fault zones are associated with salt bodies. These structures are planes of weakness. Depending on effective in-situ stress conditions these faults and intense natural fractures can become critically stressed and induce slip on plane.
Salt rheology and geochemistry pose higher drilling risk than drilling through other rocks. Salt creeps towards borehole during drilling, and plastic yielding around borehole is unavoidable when drilling through salt body. Boundary zone tends to be heavily naturally fractured, brecciated, or sheared, and rock may become unconsolidated and lose its cohesiveness. Taking heavy losses in naturally fractured boundary zone may occur. Abnormal pressure exists and taking a kick while drilling out of salt body is not uncommon.
Public domain documentation available for Arctic region support the hazards identified by our geological analysis and also suggest that a great deal of downhole uncertainty exists during early exploration. In analogous setting outside of the Arctic Circle, drilling problems related to pressure uncertainty, tight windows and wellbore stability are referenced throughout and the lessons learned suggest limiting the uncertainty when possible and the use of contingency planning.
Based on the similarities in the structural geometry of petroleum basin in Arctic and select basins in other parts of the world, it seems logical that lessons learned from these areas away from the Arctic, e.g., offshore Nova Scotia, Brazil, and Angola should provide some assistance with the planning and execution of Arctic drilling activities.
All information collection during this study has been referenced throughout. This information will be beneficial for continued support of drilling in salt tectonic structural provinces in the Arctic and anywhere else in the world.
Landing zone selection is one of the key decisions for a subsurface team in order to improve productivity and profitability in unconventional plays. The optimal position depends on a combination of parameters including petrophysical and geomechanical properties, presence of natural fractures, and the stratigraphic architecture of the reservoir.
The Vaca Muerta Formation shows a high degree of vertical heterogeneity associated to the presence of argillaceous and calcitized ash beds, concretions, calcite veins, bindstone and other limestone beds. This heterogeneity controls the mechanical behavior of the succession affecting fracture efficiency. As a result, understanding the detailed stratigraphic architecture of the reservoir is relevant for landing zone selection. This work focuses on characterizing and predicting the heterogeneity of the Vaca Muerta reservoir associated to the stacking pattern of facies and their influence in ranking landing zones.
In the last five years the Upper Jurassic-Lower Cretaceous Vaca Muerta Formation (Neuquén Basin, Argentina) has awakened international interest due to its enormous potential as an unconventional oil and gas reservoir (Figure 1).
The Vaca Muerta Formation consists primarily of a mixed, carbonate-siliciclastic, outer ramp and basinal facies in the largely progradational, shallowing-upward Quintuco-Vaca Muerta depositional system. The geometry of the system is characterized by the development of diverse clinoform geometries (Gulisano et al., 1984, Mitchum and Uliana, 1985; Massaferro et al., 2014; Reijenstein et al., 2014; Sattler et al., 2016; González et al., 2016) (Figure 2). The organic-rich strata within the Vaca Muerta Formation reach up to 350 meters and display significant vertical and lateral heterogeneity.
Sedimentological and sequence stratigraphic studies provide the geological framework for understanding the genetic relation between the depositional system, textural changes, mineralogy, TOC and diagenetic processes. All these attributes affect reservoir quality and have an impact on drilling efficiency and completion quality.
The objective of this contribution is to emphasize the importance of detailed reservoir characterization in the exploration and development of unconventional plays for landing zone selection and ranking. In particular, this work shows advances in the sedimentological and stratigraphic characterization of the Vaca Muerta Formation conducted on core at different scales of analysis.
Goodarzi, Fariborz (FG&Partners Ltd, 219 Hawkside Mews, NW, Calgary, Alberta, Canada, T3G 3J4) | Ardakani, Omid Haeri (Geological Survey of Canada - Calgary) | Pedersen, Per-Kent (Department of Geoscience, University of Calgary, Calgary, Alberta, Canada, T2N 1N4) | Sanei, Hamed (Geological Survey of Canada - Calgary, Department of Geoscience, University of Calgary, Calgary, Alberta, Canada, T2N 1N4)
Canada has vast oil shale resources (estimated at 180 billion barrels proved recoverable oil shale reserve) similar to the estimated Canadian oil reserve of 179 billion barrels. These deposits consist of various oil shale types deposited in terrestrial, lake, and marine environments. These Canadian oil shale deposits are assessed under auspices of Canada/Israel Industrial Research and Development Program and Geological Survey of Canada for their possible use for extraction of hydrocarbon. The organic rich oil shale deposit with thickness of 60m are suitable for this purpose. This paper reviews the oil shale deposits of Arctic Canada from Ordovician to Carboniferous age. Ordovician shale of Baffin Island, Southampton Island, and Akpatok Islands consist of organic lean, calcareous deposits with variable thickness.
Fantin, Manuel (Chevron Argentina) | Crousse, Luisa (Chevron Argentina) | Cuervo, Sergio (Chevron Argentina) | Vallejo, Dolores (Chevron Argentina) | Gonzalez Tomassini, Federico (Universidad de Buenos Aires) | Reijenstein, Hernan (Chevron Latin America Business Unit) | Lipinski, Christopher (Chevron Energy Technology Company)
Vaca Muerta formation is a Jurassic-Cretaceous lithostratigraphic unit in the Neuquén Basin of Argentina, well known as a world-class source rock and for its unconventional resource potential. Vaca Muerta play in the central Neuquén basin position has a remarkably thick continuous organic-rich section (approximately 350m).
Chevron Argentina is evaluating the Vaca Muerta potential in the El Trapial exploitation lease. Data available includes 500 km2 of 3D seismic data, wire-line and mud log data from 4 exploratory vertical wells with full e-log suite and 415 meter of core, and from 5 legacy wells with basic e-logs. Vaca Muerta outcrops in an analog stratigraphic setting are located 40 km away from El Trapial.
Initial results of the stratigraphic analysis were based on seismic interpretation, well log evaluations and core data analysis. Correlations and comparisons between the subsurface interpretation and the outcrops of Vaca Muerta allowed us to tie stratigraphic sequences in El Trapial to the regional framework.
This study builds upon previous regional sequence stratigraphic interpretations and provides a refined stratigraphic framework for distal facies of the Vaca Muerta. Similar to other shales worldwide, Vaca Muerta deposition was initiated with a marine transgression over non-marine deposits of the Tordillo Formation. This transgression is expressed as a condensed section with high gamma-ray and TOC values in the basal section. Accommodation changes and paleo-depositional trends were interpreted based on strata cyclicity, thickness variations, and seismic stacking patterns. An internal Vaca Muerta stratigraphic subdivision was defined based on seismic data, logs, thin sections, facies and organic geochemistry analysis.
Recognition of lateral and vertical heterogeneity within Vaca Muerta will lead to better planning and exploitation of hydrocarbons through enhanced reservoir models and improved target identification, which will ultimately reduce risks and costs. Stratigraphy plays a key role in the identification of the most productive stratigraphic interval (i.e., Sweet Spot), and most prospective region (i.e., Core Area), to develop an unconventional project.
Copyright 2014, Offshore Technology Conference This paper was prepared for presentation at the Arctic Technology Conference held in Houston, Texas, USA, 10-12 February 2014. This paper was selected for presentation by an ATC 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 Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference 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 OTC copyright. I. Introduction Overview As climate change renders the Arctic increasingly accessible, there has been a substantial uptick in industry interest in the region; it is believed an estimated $100 billion could be invested in the Arctic over the next decade. The Arctic contains vast oil and natural gas reserves--the U.S. Geological Survey estimates the Arctic could contain 1,670 trillion cubic feet (tcf) of natural gas and 90 billion barrels of oil, or 30 percent of the world's undiscovered gas and 13 percent of oil. Energy companies are certain to be at the forefront of Arctic development and investment. Climate change has played an important role in expanding access to the Arctic region, although there have been fewer opportunities to access lower cost oil and gas plays. As conventional production has declined, industry has had to focus more on difficult-to-access and unconventional oil and gas plays throughout the world, including those in the Arctic. Exploration and development in the Arctic requires expensive, tailored technologies as well as safeguards adapted to the extreme climatic conditions. In the wake of the 2010 Deepwater Horizon incident, there have been additional costs associated with emergency response and containment requirements. Regulators, as well as social and environmental groups, have been outspoken about the dangers and risks linked to Arctic energy development. Bearing in mind the enormous challenges of cleaning up an oil spill in icy conditions, the greatest concern is what kind of impact such a disaster would have on the fragile Arctic ecosystem.
This study discusses the non-Arctic nations’ strategy for the development of arctic oil and gas resources. According to the Circum-Arctic Resource Appraisal (CARA) by the U.S. Geological Survey (USGS, 2008), it was estimated that undiscovered oil and gas in the Arctic Circle accounted for, respectively, 13% (90 billion barrel; Bb) and 30% (1,670 trillion cubic feet; Tcf) of the world’s total resources. If we solve major challenges and problems in the Arctic, it will trigger exploration and production (E&P) development. It is expected that the Arctic oil and gas resources will become an alternative to supplying national future energy demand.
The Chukchi Edges project was designed to establish the relationship betweenthe Chukchi Shelf and Borderland and indirectly test theories of opening forthe Canada Basin. During this cruise, ~5300 km of 2D multi-channel seismicprofiles and other geophysical measurements (swath bathymetry, gravity,magnetics, sonobuoy refraction seismic) were collected from the RV Marcus G.Langseth across the transition between the Chukchi Shelf and ChukchiBorderland.
These profiles reveal extended basins separated by faulted high-standingblocks. Basin stratigraphy can be subdivided on the basis of gross stratalgeometry, reflection terminations and inferred unconformities. The wedge-shapedsynrift sequences terminate against the basement highs and/or major faults,burying the basement topography. The inferred postrift seismic units are morenearly tabular, but thicken locally due to compaction of underlying synriftsediments.
Reflection character is dominated by alternating high and low amplitudecontinuous reflectors which may be consistent with pelagic or turbiditesediments. Chaotic units are also observed, which may indicate mass-flowdeposits. The truncated sediments over the basement highs of the Chukchi Shelf,Chukchi Plateau and Northwind Ridge suggest major erosion due both to glacialplanation and earlier erosional events perhaps associated with basement upliftprior to or during rifting and extension.
It is believed that the bulk of the synrift sediments are Mesozoic in age.Certainly Cenozoic sediments are also preserved in these basins, but theposition of the boundary is uncertain. Locally, continuous reflectors areobserved underlying the rift basin fill. These older units, of very uncertainage, would, if sampled, provide constraint on the history and affinities of theChukchi Borderland.
In addition to the extensional basins, a number of small symmetric basinsare observed on the flanks of the Chukchi Plateau. These basins may betranstensional and argue for a 2nd phase of tectonism, which overprinted theobvious extensional fabric of the Borderland. This is supported by theobservation of uplifted postrift sediments on the flanks of some of theintermedial basement highs. Understanding the timing, distribution and extentof these two phases of tectonism, relative to the known history of N-Sextension on the Chukchi shelf and the apparent orthogonal extension observedon the Beaufort Shelf will further constrain the unknown history of the CanadaBasin.
More than 15,000 line-km of new regional seismic reflection and refractiondata in the western Arctic Ocean provide insights into the tectonic andsedimentologic history of Canada Basin, permitting development of new geologicunderstanding in one of Earth's last frontiers. These new data support arotational opening model for southern Canada Basin. There is a central basementridge possibly representing an extinct spreading center with oceanic crustalvelocities and blocky basement morphology characteristic of spreading centrecrust surrounding this ridge. Basement elevation is lower in the south, mostlydue to sediment loading subsidence. The sedimentary succession is thickest inthe southern Beaufort Sea region, reaching more than 15 km, and generally thinsto the north and west. In the north, grabens and half-grabens are indicative ofextension. Alpha-Mendeleev Ridge is a large igneous province in northernAmerasia Basin, presumably emplaced synchronously with basin formation. Itoverprints most of northern Canada Basin structure. The seafloor andsedimentary succession of Canada Basin is remarkably flat-lying in its centralregion, with little bathymetric change over most of its extent. Reflectionsthat correlate over 100s of kms comprise most of the succession and on-lapbathymetric and basement highs. They are interpreted as representing depositsfrom unconfined turbidity current flows. Sediment distribution patterns reflectchanging source directions during the basin's history. Initially, probably lateCretaceous to Paleocene synrift sediments sourced from the Alaska andMackenzie-Beaufort margins. This unit shows a progressive series of onlapunconformities with a younging trend towards Alpha and Northwind ridges, likelya response to contemporaneous subsidence. Sediment source direction appeared toshift to the Canadian Arctic Archipelago margin for the Eocene and Oligocene,likely due to uplift of Arctic islands during the Eurekan Orogeny. The finalstage of sedimentation appears to be from the Mackenzie-Beaufort region for theMiocene and Pliocene when drainage patterns shifted in the Yukon and Alaska tothe Mackenzie valley. Upturned reflections at onlap positions may indicatesyn-depositional subsidence. There is little evidence, at least at a regionalseismic data scale, of contemporaneous or post-depositional sediment reworking,suggesting little large-scale geostrophic or thermohaline-driven bottom currentactivity.
Duchesne, Mathieu J. (Geological Survey of Canada) | Brake, Virginia I. (Geological Survey of Canada) | Hu, Kezhen (Geological Survey of Canada) | Giroux, Bernard (INRS-ETE) | Walker, Emilie (Laval University)