Today, almost half of Western Canada's natural-gas production comes from the Triassic-aged Montney formation, a sixfold increase over the last 10 years while gas production from most other plays has declined. In the last few years, demand for condensate as diluent for shipping bitumen has driven development of liquids-rich Montney natural gas leading to a surge in gas production and gas-on-gas competition in the Western Canadian Sedimentary Basin (WCSB), which has driven local natural gas prices down. This has had a material effect on the operations and finances of companies active in the Western Canada and is reshaping the Canadian gas industry. A significant portion of this growth has taken place in NE British Columbia and with the planned electrification of the industry in British Columbia, including the nascent LNG operations, will influence tomorrow's power industry in this region. NE British Columbia is a geographically large area with sparse population and the power supply into this region has lagged behind development of oil and natural gas resources. The area was originally served from geographically closer NW Alberta. More recently, supply was established from the BC Hydro power grid with the most significant developments being Dawson Creek-Chetwynd Area Transmission (DCAT) completed in 2016 and the additional 230 kV transmission projects scheduled for completion in 2021.
Hydrodynamics and geothermics are important tools for understanding the complex distribution of reservoir fluids in the Montney Formation in Alberta and British Columbia, Canada. The Montney comprises a conventional system in the east and an unconventional, Deep Basin-style hydrocarbon system in the west, where an underpressured, oil-dominated fairway just west and downdip of the conventional system grades further downdip into overpressured liquids and gas fairways.
The first part of this study addresses how these systems can be mapped from a pressure and temperature perspective. The Montney hydrodynamics system is explained using pressure versus elevation graphs. Key contours are taken from pressure-depth ratio maps to define the general boundaries between systems, noting that these boundaries change with depth. Geothermal gradient mapping is used to identify areas of prominent high or low geothermal gradients, which can have a significant effect on the positioning of gas liquids fairways. Key current day isotherms are also identified to represent the current phase windows by relating present-day formation temperatures to Tmax data.
To evaluate how pressure and temperature affect liquids production within the Montney, liquids production trends need to be considered. The second half of the paper discusses how mapping gas composition, particularly C2+ Wet Gas Index (WGI), may serve as a good proxy for liquids yields.
While the authors appreciate the complexities of phase behavior and the various factors influencing liquids production, the objective of this paper is to link trends that can be observed in liquids production to trends in pressure, temperature and gas composition. Ultimately, this paper examines ways in which hydrodynamics and geothermics can be used to help predict spatial variations in observed liquids production. By analyzing the co-relationships of the pressure, temperature and WGI data, the Montney segregates into two distinct domains which we term the Northern (British Columbia) Play and the Southern (Alberta) Play. This analysis can be tied in with other data sets for a better understanding of the reservoir such as: isotope geochemistry to gain insights into hydrocarbon migration; Special Core Analysis (SCAL) data to gain insights into fluid mobility; vapour-liquid equilibrium data to examine hydrocarbon fractionation during production; and completions data to provide a more complete picture of reservoir deliverability.
Africa (Sub-Sahara) Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). Asia Pacific Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir. Following evaluation operations, the well will be sidetracked to drill the Singa Laut prospect in an adjacent fault block. Premier is the operator (65%), with partner Mitsui Oil Exploration Company (35%).
The Prudhoe Bay field, located on the North Slope of Alaska, is the largest oil and gas field in North America. The main Permo-Triassic reservoir is a thick deltaic high-quality sandstone deposit about 500 ft thick with porosities of 15 to 30% BV and permeabilities ranging from 50 to 3,000 md. The field contains 20 109 bbl of oil overlain by a 35 Tcf gas cap. Under much of the oil column area, there is a 20- to 60-ft-thick tar mat located above the oil-water contact (OWC).
Whidden, Katherine (U.S. Geological Survey) | Birdwell, Justin (U.S. Geological Survey) | Dumoulin, Julie (U.S. Geological Survey) | Fonteneau, Lionel (Corescan Pty Ltd) | Martini, Brigette (Corescan Pty Ltd)
The Middle – Upper Triassic Shublik Formation is an organic-rich heterogeneous carbonate-siliciclastic-phosphatic unit that generated much of the oil in the Prudhoe Bay field and other hydrocarbon accumulations in northern Alaska. A large dataset, including total organic carbon (TOC), X-ray diffraction (XRD), X-ray fluorescence (XRF) and inductively coupled plasma – mass spectrometry (ICP-MS) measurements, has been built from core and outcrop samples of the Shublik, with a focus on the organic-rich intervals. In addition, two core intervals from the Shublik were analyzed using a hyperspectral imaging system in the visible, near-infrared and shortwave-infrared range. Integration of the hyperspectral results with core descriptions, microfacies interpretations, and analytical data is being used to decipher mudstone depositional and diagenetic processes.
Petrographic analysis of Upper Triassic organic-rich intervals within the Shublik suggests that the main microfacies is a laminated bioclastic wackestone/packstone that was episodically disrupted by energetic events of variable intensity. These energetic events produced transitional and sparry calcite bioclastic packstone to grainstone intervals, depending on the depth of sediment column disturbance. By using hyperspectral imaging data from the Ikpikpuk core, individual distribution maps for minerals of interest have been generated and corroborate the microfacies interpretations. These maps also illustrate small-scale vertical changes in mineralogy. The laminated bioclastic wackestone/packstone intervals contain less calcite than the adjacent sparry bioclastic packstone to grainstone intervals. The calcite in these laminated intervals is more iron rich. This interpretation suggests that lower iron concentrations should be expected in the disrupted intervals than in nearby laminated intervals. Textural features are also enhanced in the hyperspectral images relative to visual description of the cores by combining the extraction of the average reflectance in the visible part of the electromagnetic spectrum and the depth of the main carbonate-related feature belonging to calcite. Examples noted in the enhanced imagery include low-angle features, calcite grain-size, and the size, shape and orientation of phosphatic nodules. This enhancement is being used to differentiate laminated from sparry bioclastic packstone to grainstone-rich intervals and provides a more comprehensive assessment of the microfacies than is practical by thin-section analysis.
The Montney Formation is a major shale gas and shale oil producing stratigraphical unit of Lower Triassic age in the Western Canadian Sedimentary Basin in British Columbia and Alberta. The potential resource is estimated at 449 trillion cubic feet of marketable natural gas, 14,521 million barrels of marketable natural gas liquids (NGLs) and 1,125 million barrels of oil. The hydrocarbon resource is unlocked using horizontal drilling followed by various fracture stimulation techniques from 25 to 75+ stages. As stage counts increase and lateral lengths are extended further to stimulate more formation, the challenges of efficiently completing a producing well is a continuous cycle of technique development and equipment improvements.
Hydraulic isolation between fracture stimulation stages is established using mechanical methods deployed as an integral part of the production casing string or inserted into the production casing string during the fracture stimulation. In the Montney, the method of
Steiner, Stefan (ADNOC Upstream) | Dasgupta, Suvodip (Schlumberger) | Basioni, Mahmoud (ADNOC Upstream) | Al Aryani, Fatima (ADNOC Upstream) | Noufal, Abdelwahab (ADNOC Upstream) | Mills, Carey (ADNOC Upstream) | Mandl, Johannes (ADNOC Upstream) | Menon, Pradeep (ADNOC Upstream) | Raina, Ishan (Schlumberger) | Mosse, Laurent (Schlumberger) | Shasmal, Sudipan (Schlumberger) | Hollaender, Florian (Schlumberger) | Ali, Humair (Schlumberger) | Al Afeefi, Baraka (Schlumberger) | Sookram, Neil (Schlumberger)
Exploration drilling for gas potential in Khuff Formation started more than 40 years ago and wells across multiple assets in offshore Abu Dhabi showed the presence of sizeable reserves. With increasing recent importance on gas production, there is a plan for moving towards development for those Permian tight gas structures to address the nation's gas needs. This paper will try to address the lessons learned from the recent appraisal wells in Khuff, the uncertainties and the success criteria.
There have been multiple wells drilled through the Khuff Formation in Offshore UAE in the last two years and have yielded a wealth of information from downhole well logs, mud logs, well test results and core data. The downhole logs acquired in these wells ranged from basic triple-combo and mud logs to image and dipole sonic logs, along with formation testing and sampling measurements, followed by well tests across the zones of interest. Interpretation of all these data have revealed some interesting lessons learned.
The shallow marine sequence of the Khuff Formation is generally characterized by poor porosity and low matrix permeability; however, the diagenetic overprint has resulted in a significant heterogeneity development, which controls the present-day porosity and permeability development at the wells. The well test results show variations in terms of 2 or 3 orders of magnitude at the same interval, which highlights potentially problematic development strategies. We have observed significant differences in terms of lithology, porosity and other reservoir quality indicators between wells, located a kilometre apart. Optimization of logging suite to minimize petrophysical evaluation uncertainty will be discussed. Characterising this heterogeneity is key for future economic success of this play. Possible role of fractures influencing flow from the Khuff have been discussed in older publications, however no conclusions were arrived at, with certainty. Presence of fractures and faults beyond the immediate vicinity of the well might be something to look at, in terms of understanding the potential productivity of those intervals. A big step for developing Khuff Formation might be in terms of deciding the optimal stimulation strategy and this is something, which remains to be studied extensively in UAE.
Closing the loop of interpretation of the acquired logs with the final well-test results and production logs gives us the advantage of hindsight and helps us in separating out the key productivity indicators as well as bring out the uncertainties in formation evaluation, which affect these tight gas reservoirs.
To keep pace with increasing importance of unconventional hydrocarbons and consequent changes in the global energy landscape, the State of Kuwait has embarked on a strategic plan of evaluating and developing these resources. Synergistic interpretation of exploration datasets has brought out the exploration potential of the resources. These resources are prolific and occur at multiple stratigraphic levels in diverse settings in carbonate reservoirs.
Two types of unconventional resources, self-sourced hydrocarbons (shale hydrocarbons) and tight hydrocarbons, have been identified and evaluated with workflows specific to each type. The Cretaceous Makhul and the Jurassic Najmah formations have emerged as important self-sourced hydrocarbon reservoirs. The play existence is demonstrated by the presence of free hydrocarbons contents, substantial thickness, overpressures and positive production tests in both plays. The Makhul play is characterized by total organic carbon (TOC) content between 4 - 7% and lies in the middle to late maturity oil window. It is over-pressured and has thickness in the range of 70 - 300 ft. The Najmah play is characterized by TOC content between 9 - 14% and is in the late maturity oil-condensate window. The play is systematically over-pressured, with pressure reaching the natural fracturing conditions. The Najmah play has shale gas and shale oil resource potential, while the Makhul play has potential for shale oil resource. The other speculative shale gas play is Qusaiba Shale which has not been drilled so far in Kuwait. Fractured carbonate units in the Cretaceous Upper Minagish and Upper Makhul; the Jurassic Hith, Najmah, Upper Sargelu and Marrat; and the Triassic Lower Jilh and Lower Khuff constitute the tight reservoir resources. These reservoirs are characterized by porosity typically less than 5% and permeability mostly less than 0.1 millidarcy (mD). These reservoirs are productive in structurally deformed areas where natural open fractures are well developed and critically stressed.
Resource specific and technology intensive multi-disciplinary workflows from play assessment to commercial production are crucial for effective leverage of the unconventional resources.
A major Permo-Triassic carbonate gas reservoir that was deposited on a very broad, shallow, restricted marine platform across the Arabian plate consists of interbedded carbonates and evaporites with episodes of minor windblown clastic influx. The reservoir has several characterization challenges including: heterogeneous mineralogy, rapidly varying sediment layers, constrained grain sizes (indicating very low initial energy differentiation in the sediments constituting the facies) combined with subsequent lateral reworking in the transgressive systems tract, thin parasequences, aerial exposure, lateral reworking and multiple episodes of diagenesis. During more than three decades of production, many studies have attempted to characterize this formation for the optimization of the gas production. Matching the production history and predicting the dynamic behavior of current and planned wells in this reservoir is still a difficult task. Highly variable mineralogy and pore types suggest significant vertical and lateral variations in the reservoir property parameters used to determine reservoir gas saturation and productivity. This work focuses on the integration of the detailed depositional facies model with the Pressure Depletion Petrophysical Rock Types (PDPRT) developed by Clerke and Al-Nasser to improve the reservoir performance prediction.
We use a comprehensive (~1000 feet of core covering ~220 depositional para sequences) set of cored wells and a carefully designed core analysis program to develop a database defining important links between facies and PDPRT's. Of the nine depositional facies defined by sedimentologists, five of them have reservoir potential. The results from this thorough program improves the hydrocarbon saturation calculation and the prediction of reservoir dynamics during pressure depletion. This state of the art characterization workflow includes: core description, thin section examination, petrographic analysis, mineralogy at multiple scales, routine core analysis (RCA) at multiple overburdens, mercury injection capillary pressure (MICP) measurements, porous plate data, and Archie parameter determination.
The Pressure Depletion Petrophysical Rock Types (PDPRT)-pore types for the highly variable carbonate lithology are defined using a two stage classification: first on the continuous mineral framework defined from QEMSCAN (Quantitative Evaluation of Minerals by Scanning Electron Microscopy) mineralogy images and then by the dominant pore type using quantitative petrographic data. These PDPRT's-pore types are also completely characterized by their Thomeer pore system parameters obtained from analyzed MICP data. These data define the pore throats of the rock-pore types in detail and with greater petrophysical rock type contrast than the conventional poro-perm method.
We obtain and also present here the significant links discovered between the depositional facies and our petrophysical rock-pore types. Integrating depositional (and depositionally related diagenetic) patterns with petrophysical rock typing greatly improves the reservoir dynamics prediction. Additional improvements come from the observation that early anhydrite reservoir pore cements result from the vertical juxtaposition of cycle-capping, tidal-flat facies with reservoir bodies in underlying parasequences. These links significantly improve reservoir model water saturation calculations and permeability predictions, which then leads to improved well placement, reduced CAPEX, production optimization and improved OGIP estimates.
Zhang, Wengang (Chongqing University) | Han, Liang (Chongqing University) | Yang, Changyou (Chongqing University) | Zhou, Xiaowan (Chongqing University) | Wu, Chongzhi (Chongqing University) | Goh, ATC (Nanyang Technological University)
The Bukit Timah Granite (BTG) formation is widely distributed in the central and northern parts of Singapore Island. This paper presents the key mechanical and physical properties of Singapore BTG rocks and residual soils, based on the Factual Geotechnical Reports of Downtown Line stage II sites. The variations of parameters including the index properties, the hydraulics, the strength and stiffness, the compressibility for residual soils, the unconfined compressive strength, the point load strength index, the abrasivity, and slake durability index for rocks are derived from laboratory tests based on samples from different depths of different borelogs. Statistical information including the average mean values, the standard deviations and the coefficient of variations are provided for these parameters. It is hoped that these statistics will provide useful reference and insights for future projects involving in BTG Formation.
The Bukit Timah Granite (BTG) is an acidic igneous rock formed in the lower middle Triassic period. There is considerable hybridization of the rock within the formation and evidence of assimilation (Pitts, 1984). Therefore, there is also a great variation in the mechanical and physical properties of BTG rocks. Through field investigations and laboratory tests, Zhao et al (1994) investigated the influences of the weathering grade and the weathering processes on the mechanical and physical properties of the weathered granitic rocks. Rahardjo et al (2012) compiled the variation of index and engineering properties of BTG residual soils with depth. Based on a large database from the Factual Geotechnical Reports on over 200 boreholes of the Singapore Downtown Line stage II (DTL2), this study presents the key mechanical and physical properties of BTG rocks and residual soils.
2. Properties of BTG rocks
2.1 Unconfined compressive strength (UCS)
In this unconfined compressive strength test, the test specimen, the loading rate as well as the testing environment are shown in Table 1.
As can be seen from Table 1, the specimens in the test are generally standard test specimens. For some of them, due to sampling or storage, the specimen is not standard in geometry, and its tested strength needs to be converted to the value under standard condition (H/D=2). The specific calculation is performed according to equations (1) and (2) (ASTM 1986).