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Abstract The Ivar Aasen (IA) oilfield is located on the Gudrun Terrace on the eastern flank of the Viking Graben in the Norwegian North Sea. The field was discovered in 2008. The reservoir is located within a sedimentary sequence of Mid-Jurassic to Late-Triassic age, which consists of shallow marine to fluvial, alluvial, floodplain and lacustrine deposits overlying a regionally extensive, fractured calcrete interval. The sequence exhibits a complex mineral composition and is heterogeneous at a scale below that of a logging sensor. Shale layers, re-deposited shale and what was first believed to be redeposited calcrete fragments present in various forms throughout the sequence. Looking more in depth to XRD and XRF data and contrasting Fe concentration in the dolomite, it is also possible to explain some of the carbonate deposits through other processes. Extensive data acquisition in the form of advanced wireline logs and coring with analysis performed in “geopilot” wells before production start, enabled a novel thin bed formation evaluation technique based on the modified Thomas-Stieber method (Johansen et al. 2018). The method increased the in-place oil volumes within the Triassic reservoir zone internally named Skagerrak 2. This led to several improvements and a modified drainage strategy of Ivar Aasen. Several good producers were placed in the complex net of the Skagerrak 2 Formation. Results from these producers have encouraged development of an even more marginal and complex net, deeper into the Triassic sedimentary sequence. Therefore, another “geopilot” was drilled into the deeper Triassic sediments, internally named as the Alluvial Fan. This zone exhibits conglomerate clasts in a matrix varying between clay, silt, feldspars, and very fine to very coarse sand fractions, grading towards gravel. Previously, this zone was considered to be mostly non-net. Applying the same interpretation method as for Skagerrak 2, the Alluvial Fan promised economic hydrocarbon volumes. The latest geopilot proved producible hydrocarbons, and subsequently a producer was also successfully placed in this part of the reservoir. Production data and history matching from the beginning of production have for a long while established the previous increase of IA Triassic oil volumes published in 2018. Advanced studies of mineralogy and spectroscopy (Johansen et al. 2019) have indicated that a significant amount of the previously interpreted dolomite, could be reinterpreted as ferroan dolomite. The latter is a heavier mineral that increases the matrix density, hence also the total porosity. The additional findings described provided another necessary first-order correction to further enhance the evergreen geomodel. This paper describes this methodology which resulted in improved petrophysics and reservoir properties of the Alluvial Fan, yet again demonstrating the value of advanced wireline logs and detailed analysis that in total impacts the IA reserve volumes in a significant manner. Repeated success with the applied spectroscopy data and the thin bed methodology used today (Johansen et al. 2018), has resulted in even the deeper Braid Plain Formation becoming of economic interest. It is expected to lie within the oil zone in an upthrow block in the northern part of the IA field and could be developed into the next target.
Abstract The North West Shelf of Australia contains a late Paleozoic to Cenozoic sedimentary succession, which attains a thickness of over 10 km and is dominated by Triassic to Lower Cretaceous sediments. The deeper plays exist at multiple stratigraphic levels including oil-prone Jurassic sediments and faulted gas-prone Triassic sediments. The area has been proven difficult as far as seismic imaging is concerned, particularly over the Madeline trend. The presence of a hard, rugose water bottom, strong reflectors beneath the water bottom, and shallow Tertiary carbonates make the Dampier Sub-basin vulnerable to multiple contamination, amplitude distortion, lower signal-to-noise ratio (S/N) and unreliable AVO response. Poor seismic quality in the data has been a significant barrier to reducing exploration risk. In the 1990s, East Dampier (1992, blue polygon in Figure 1) and Keast (1997, yellow polygon in Figure 1) seismic data were acquired in East-West and North-South directions respectively, in an effort to better understand the impact from the shallow complex overburden. To address these challenges, the Demeter survey was acquired in 2003 (black polygon in Figure 1) with a denser acquisition grid. The overall seismic quality was improved, but the results still contained a significant level of residual multiples. Later, the Fortuna survey, the most comprehensive multi-sensor seismic survey on the North West Shelf of Australia to date, was acquired in 2014 with the aim to provide better subsurface imaging (pink polygon in Figure 1) from different acquisition perspectives. The data was processed with advanced processing technology, including shallow water demultiple, deghosting and high definition tilted orthorhombic velocity model building (Birdus et al., 2017). However, the final results were still suffering from a number of challenges, specifically: 1) strong residual multiple in near offsets, 2) low S/N ratio, particularly at reservoir level, and 3) inconsistency from near to far stack resulting in unreliable AVO. In this paper, the Dixon area (green polygon), considered as the most challenging area in the Dampier Sub-basin, was chosen as the testing area for our work. By integrating high-end imaging technology, for example dual-sensor deghosting, multi-survey surface related multiple elimination (MAZ-SRME), and multi-azimuth processing (MAZ stack), we will illustrate how we have overcome many of these imaging challenges.
Soroush, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Hosseini, Seyed Abolhassan (University of Alberta and RGL Reservoir Management Inc.) | Mohammadtabar, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Pourafshary, Peyman (Nazarbayev University) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Ghalambor, Ali (Oil Center Research International) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.)
Summary Kazakhstan owns one of the largest global oil reserves (approximately 3%). This paper aims at investigating the challenges and potentials for production from weakly consolidated and unconsolidated oil sandstone reserves in Kazakhstan. We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves in Kazakhstan were studied in terms of the depth, pay‐zone thickness, viscosity, particle‐size distribution (PSD), clay content, porosity, permeability, gas cap, bottomwater, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, the geological condition, including the existing structures, layers, and formations, were addressed for different reserves. Weakly consolidated heavy‐oil reserves in shallow depths (less than 500‐m true vertical depth) with oil viscosity of approximately 500 cp and thin pay zones (less than 10 m) have been successfully produced using cold methods; however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical compared with the similar cases in North America. The complicated tectonic history necessitates geomechanical models to strategize the sand control, especially in cased and perforated completions. These models are usually avoided in North America because of the less‐problematic conditions. Further investigation has shown that inflow‐control devices (ICDs) could be used to limit the water breakthrough, because water coning is a common problem that begins and intensifies the sanding. This paper provides a review on challenges and potentials for sand control and sand management in heavy‐oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.
Makeev, A. A. (Oil and Gas Production Department Bystrinskneft, Surgutneftegas PJSC) | Tseplyaeva, A. I. (Industrial University of Tyumen) | Leontev, S. A. (Industrial University of Tyumen) | Shay, E. L. (Oil and Gas Production Department Bystrinskneft, Surgutneftegas PJSC)
The article highlights geological and physical features of the pre-Jurassic Triassic complex. Promising targets for prospecting and exploration of oil depositions have been outlined. Consistent patterns associated with reservoir type and dynamic parameters of wells have been identified. Mixed type wells (porous-fractured, porous and fractured) demonstrate a relatively stable production rate. Wells with predominantly fractured reservoir type demonstrate a rapid decline in production. Oil production from wells of the pre-Jurassic complex (the Triassic period) is performed using electrical submersible pumps (ESP). High formation temperature of 116°C, total salt content of about 50 g/l in the produced formation fluid, GOR over 120 m3/m3 are considered as complicating factors for the Triassic target operation. Decrease in the time between failures in the wells of the pre-Jurassic complex (the Triassic period) is caused by the formation of salt residues. Measures were taken to increase the mean time between failures of ESP units. The well stock has been divided into groups; salt hazard categories have been identified for each well group. Criteria for the use of additional ESP units at the salt hazardous well stock of the pre-Jurassic complex (the Triassic period) have been identified. The methodology for the use of an inhibitor for salt depositions has been developed to determine the priority of wells treatment. The saturation index has been defined taking into account the temperature increase in the pump to improve the efficiency of forecasting salt depositions formation in wells of the pre-Jurassic Triassic complex. The methodologies applied to the wells of the pre-Jurassic complex (the Triassic period) allowed to achieve the mean time between failures of 637 days and to increase the work efficiency at the salt hazardous well stock.
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. The oil averages 27.6 API gravity and has an original solution gas-oil ratio (GOR) of about 735 scf/STB. Under much of the oil column area, there is a 20- to 60-ft-thick tar mat located above the oil-water contact (OWC).
Lundin Energy has completed exploration well 7221/4-1, targeting the Polmak prospect in licenses PL609 and PL1027, in the southern Barents Sea. The well was meant to prove hydrocarbons in Triassic-aged sandstones within the Kobbe formation of the Polmak prospect. After finding indications of hydrocarbons in a 9-m interval in poor-quality reservoir in the targeted formation, the well was classified as dry. The well was drilled 30 km east of the Johan Castberg discovery, by the Seadrill-operated West Bollsta semisubmersible rig. Lundin Energy, operator of Polmak, holds a 47.51% working interest.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 202894, “Cased Hole Standalone Evaluation: Breaking the Barrier To Successfully Evaluate Challenging Deep Carbonate Reservoirs,” by Pradeep Menon and Carey Mills, ADNOC, and Suvodip Dasgupta, SPE, Schlumberger, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. Accurate petrophysical evaluations (formation lithology, porosity, and water saturation) are essential in characterizing potential reservoir zones and estimating resources in place. Typically, these evaluations rely on acquisition of openhole logging measurements; however, this is not always possible. The complete paper outlines two examples from tight gas reservoirs in two separate fields offshore Abu Dhabi in which openhole data could not be acquired and petrophysical analysis was undertaken using cased-hole log data. These evaluations successfully identified gas-saturated porous intervals in each well, one of which was successfully flow-tested. Introduction A growing need exists to increase gas production in the UAE. As a result, specific gas-production targets have been mandated from development of currently undeveloped deep gas carbonate reservoirs such as the Permo-Triassic Khuff formation, the middle Jurassic Araej formation, and the Permian Pre-Khuff Unayzah and Berwarth formations. Recent appraisal wells have aimed at evaluating these reservoirs systematically by acquiring a good suite of openhole logs, cutting conventional cores, and conducting well-testing operations. These well data are combined with an evolving regional understanding to better assess and ultimately develop these complex formations. An accurate petrophysical evaluation requires the petrophysicist to develop a realistic evaluation of formation lithology, porosity, and water saturation. These parameters provide the foundations for further work such as static modeling stands, and they must be robust. The Upper Khuff is composed of dolomite occasionally grading to calcareous dolomite with minor interbeds of claystone and anhydrite. In core and cuttings, the dolomite in the uppermost section exhibits a grainstone texture with poor intercrystalline/intergranular porosity. The Lower Khuff is composed of very hard dolomite in part grading to calcareous dolomite, medium-to-dark grey-brown in places, with occasional very-fine-to-medium grainstone texture and very poor intercrystalline porosity. In this paper, the Upper and Lower Araej members are interpreted to have been deposited in an open, marine- circulation shelfal environment, while the Uweinat member is considered to have been deposited in a more- restricted circulation setting with-in a similar shelfal environment. The Barrier Openhole logging generally is the preference for formation evaluation because it represents the simplest environments and benefits from a comprehensive list of available measurements. The variety of tools and diversity of output data available make openhole log acquisition the gold standard for formation evaluation. However, in certain situations in which openhole logging is not possible because of borehole conditions (re-entry of old cased wells, wellbore instability, over-pressure), no option exists other than acquiring petrophysical data in a cased-hole environment.
GOM Lease Sale Generates $121 Million in High Bids; Shell Offshore Takes Top Spot Regionwide US Gulf of Mexico (GOM) Lease Sale 256 generated $120,868,274 in high bids for 93 tracts in federal waters. The sale on 18 November featured 14,862 unleased blocks covering 121,875 square miles. With $27,877,809 spanning 21 high bids, Shell Offshore Inc. took the top spot among 23 competing companies. A total of $135,558,336 was offered in 105 bids. Among the majors, Shell, Equinor, BP, and Chevron submitted some of the highest bids. Each company claimed high bids of over $17 million, signaling the GOM remains a priority in their portfolios. Last year was a record year for American offshore oil production at 596.9 million bbl, or 15% of domestic oil production, and $5.7 billion in direct revenues to the government. Offshore oil and gas supported 275,000 total domestic jobs and $60 billion total economic contributions in the US. “The sustained presence of large deposits of hydrocarbons in these waters will continue to draw the interest of industry for decades to come,” Deputy Secretary of the Interior Kate MacGregor said. Still, as Mfon Usoro, senior research analyst at Wood Mackenzie, noted, “Although bidding activity increased by 30% from the March 2020 sale, the high bid amount of $121 million still trends below the average high bid amount seen in previous regionwide lease sales, proving that companies are still being conservative with exploration spend.” Although the Bureau of Ocean Energy Management has proposed another regionwide GOM lease sale in March 2021, Usoro predicted that Lease Sale 256 “could potentially be one of the last lease sales.” “With the Biden administration set to inaugurate next year and possibly ban future lease sales, a massive land grab might have ensued,” he continued. “But companies are constrained by tight budgets due to the prevailing low oil price. Additionally, companies in the region have existing drilling inventory to sustain them in the near term. The best blocks with the highest potential reserves are likely already leased. As a result, we do not expect a potential ban on leasing to materially impact production in the region until the end of the decade.” This was the seventh offshore sale held under the 2017–2022 National Outer Continental Shelf Oil and Gas Leasing Program; two sales a year for 10 total regionwide lease sales are scheduled for the gulf. Nine Areas on Norwegian Continental Shelf Open for Bids The 25th licensing round on the Norwegian Continental Shelf, comprising eight areas in the Barents Sea and one in the Norwegian Sea, has been announced by the Norwegian Ministry of Petroleum and Energy. Known for being a country with some of the greenest credentials and policies in the world, Norway surprised observers in June by announcing plans for a licensing round that signaled further oil exploration in the Norwegian sector of the Arctic Sea. In this round, 136 blocks/parts of blocks will be available: 11 in the Norwegian Sea and 125 in the Barents Sea. The application deadline for companies is 23 February 2021. New production licenses will be awarded in Q2 2021. Johan Sverdrup Capacity Increased to Half Million B/D Following positive results in a November capacity test, the Johan Sverdrup field is set to increase daily production capacity. Capacity will rise from today’s 470,000 to around 500,000 B/D in the second increase since the field came on stream just over a year ago. The move will increase the field’s total production capacity by around 60,000 bbl more than the original basis when the field came on line. Overall, the field is estimated to have resources of 2.7 billion BOE. “The field has low operating costs, providing revenue for the companies and Norwegian society, even in periods with low prices,” said Jez Averty, Equinor’s senior vice president for operations south in development and production, Norway. The Johan Sverdrup field uses water injection to secure high recovery of reserves and maintain production at a high level. An increase in the water-injection capacity should further increase production capacity by mid-2021, according to Rune Nedregaard, vice president for Johan Sverdrup operations. Phase 2 production starting in Q4 2022 will raise the Johan Sverdrup full-field plateau production capacity from 690,000 to around 720,000 B/D. Equinor operates the field with 42.6% stake; other partners include Lundin Norway (20%), Petoro (17.36%), Aker BP (11.57%), and Total (8.44%). ConocoPhillips Makes Significant Gas Discovery Offshore Norway ConocoPhillips announced a new natural-gas condensate discovery in production license 1009, located 22 miles northwest of the Heidrun oil and gas field and 150 miles offshore Norway in the Norwegian Sea. The wildcat well 6507/4-1 (Warka) was drilled in 1,312 ft of water to a total depth of 16,355 ft. Preliminary estimates place the size of the discovery between 50 and 190 million BOE. Further appraisals will determine potential flow rates, the reservoir’s ultimate resource recovery, and plans for development. “The Warka discovery and potential future opportunities represent very low cost-of-supply resource additions that can extend our multi-decade success on the Norwegian Continental Shelf,” said Matt Fox, executive vice president and chief operating officer. The drilling operation, which was permitted to ConocoPhillips in August 2020, was performed by the Transocean-managed Leiv Eiriksson semisubmersible rig. ConocoPhillips Skandinavia AS is the main operator of the license with a 65% working interest; PGNiG Upstream Norway AS holds the remaining stake. Lundin Energy Completes Barents Sea Exploration Well, Comes Up Dry Lundin Energy has completed exploration well 7221/4-1, targeting the Polmak prospect in licenses PL609 and PL1027, in the southern Barents Sea. The well was meant to prove hydrocarbons in Triassic-aged sandstones within the Kobbe formation of the Polmak prospect. After finding indications of hydrocarbons in a 9-m interval in poor-quality reservoir in the targeted formation, the well was classified as dry. The well was drilled 30 km east of the Johan Castberg discovery, by the Seadrill-operated West Bollsta semisubmersible rig. Lundin Energy, operator of Polmak, holds a 47.51% working interest. Partners are Wintershall DEA Norge AS (25%), Inpex Norge AS (10%), DNO Norge AS (10%), and Idemitsu Petroleum Norge AS (7.5%). Polmak is the first of Lundin’s three high-impact exploration prospects drilled this quarter in the Barents Sea; the wells target gross unrisked prospective resources of over 800 million bbl of oil. The West Bollsta rig will now proceed to drill the Lundin Energy-operated Bask prospect in PL533B. Well 7219/11-1 will target Paleocene-aged sandstones, estimated to hold gross unrisked prospective resources of 250 million bbl of oil. Tullow Sells Remaining Stake in Ugandan Oil Field Tullow Oil has completed the 10 November sale of its assets in Uganda to French giant Total for $500 million. Tullow will also receive $75 million when a final investment decision is taken on the development project, calculated to hold 1.7 billion bbl of crude oil. Contingent payments are payable after production begins if Brent crude prices rise above $62/bbl. The completion of this transaction marks Tullow’s exit from its licenses in Uganda after 16 years of operations in the Lake Albert basin. The deal is designed to strengthen Tullow’s balance sheet, as tumbling crude prices combined with exploration setbacks have created problems for the company. In September, the company reported that it had lost $1.3 billion in the first 6 months of 2020 as falling oil prices forced it to write down the value of its assets. The deal cut Tullow’s net debt to $2.4 billion; it has $1 billion in cash.