Leman Sandstone Research Articles

Aeolian–lacustrine margins: implications for carbon capture and storage within the Rotliegend Group, Southern North Sea

The Southern North Sea Basins of the United Kingdom were renowned for their hydrocarbon resources and exploited extensively from the 1960s to the 1990s. The Permian Leman Sandstone in particular formed an excellent reservoir due to its extensive clean aeolian sediments and was subsequently explored for decades, resulting in a wealth of subsurface data that are now widely accessible. The strata of the Leman Sandstone comprises mixed continental deposits from aeolian, fluvial and lacustrine environments which interfinger with the saline lake deposits of the Silverpit Formation. With the potential reassessment of depleted gas reservoirs in the North Sea for use as sequestration targets for captured carbon dioxide, there is significant renewed interest in the reservoir geology of the Leman Sandstone. A regional study of the sedimentology and petrophysical properties of the Leman Sandstone and Silverpit formations within quadrants 43, 44, 48 and 49 of the Southern North Sea has been conducted. Multiple interactions between the depositional environments are observed, resulting in a complex interplay between aeolian and lacustrine transgressive/regressive events, and migration and expansion/contraction of the fluvial system. In wireline petrophysical data, each depositional environment, along with their transitional environments, form relatively distinct clusters that can be used as a predictive tool for reservoir interpretation in the absence of core, despite extensive sediment recycling between environments.

A method for fine-scale vertical heterogeneity quantification from well data and its application to siliciclastic reservoirs of the UKCS

The character of a geological reservoir is critical to the behaviour of fluids that are extracted from it or injected into it, and thus can determine the economic viability of a subsurface project. There are a range of variables of interest when characterising a reservoir. One of these is the degree of heterogeneity, a function of the variability of rock properties resulting from various depositional and post-depositional processes. Heterogeneous reservoirs typically pose more challenges than homogenous reservoirs. The quantification of heterogeneity is therefore of importance for hydrocarbon exploration and production and will become increasingly important for evaluating “advantaged” hydrocarbons and the suitability of sites for subsurface storage. Numerous approaches have been used to quantify geological heterogeneity, but each only provides an estimate of the true heterogeneity and lacks the ability to quantify fine-scale variability. Here we propose an approach that can quantify the fine-scale vertical heterogeneity from well logs and demonstrate our approach on siliciclastic reservoirs of the United Kingdom Continental Shelf (UKCS). We analyse the Leman Sandstone Formation, Bunter Sandstone Formation, Maureen Sandstone Member, Andrew Sandstone Member, Balmoral Sandstone Member, and Forties Sandstone Member, which are important from both petroleum and energy transition perspectives. Our approach can be used to provide new insights into the differences between units and the geospatial nature of heterogeneity within each unit. This can be used to support evaluation/screening activity and to identify suitable analogues from which geologically plausible 3D reservoir models can be generated in a data-driven manner.

Use of Subsurface Geology in Assessing the Optimal Co-Location of CO2 Storage and Wind Energy Sites

Opportunities exist to re-purpose depleted gas fields in the Southern North Sea as CO2 storage sites if, where and when they meet the right set of geological, engineering, and non-technical criteria. Fields positioned on the western edge of the basin are attractive as they lie close to the major industrial emitters of East England which need to decarbonise if the UK’s Net Zero targets are to be met. Having stopped production in 2018, Pickerill has CO2 storage potential as it is a proven trap from which around 440 Bcf of gas has been produced and it is located near the coastline. We use a public-domain 3D seismic dataset, wireline logs, core reports and production data to assess its CO2 storage potential. The Rotliegend Group reservoir (Leman Sandstone Formation) is a mixed aeolian/fluvial succession with variable thickness (25 m–80 m), high net-to-gross (0.9–1.0), moderate average porosity (9%–17%) and fair-average permeability (>1 mD). The seal is Zechstein Group evaporites and carbonates which thin and swell in response to their post-depositional mobility (halokinesis), further affecting and deforming the overburden. The structure is defined to the south by a WNW-ESE-striking fault system, but the north of the field is characterised mostly by dip closure of the reservoir. NW-SE-striking faults transect the field and segment the structure into several compartments, three of which appear particularly good candidates for CO2 storage and have a combined CO2 storage capacity of 32 MtCO2. If combined with nearby satellite fields, there is potential for the development of a CO2 storage cluster capable of sequestering 60 MtCO2, however, this potential is challenged by the planned development of an offshore wind farm. Turbines fixed to the seabed over the field would restrict where new CO2 injection wells might be drilled and efforts to measure, monitor and verify the CO2 plume using conventional towed-streamer seismic. There is an urgent need to resolve the competition for offshore acreage to ensure that attractive CO2 storage sites like Pickerill are not disadvantaged but can play a full part in complementing alternative renewable energy sources within the energy transition.

Structural evolution of the Breagh area: implications for carboniferous prospectivity of the Mid North Sea High, Southern North Sea

Exploration success at Breagh demonstrates that western parts of the Mid North Sea High area are prospective despite the absence of an Upper Permian (Rotliegend Group) Leman Sandstone Formation reservoir and source rocks belonging to the Upper Carboniferous Westphalian Coal Measures Group. Detailed seismic and well interpretation shows that the Breagh trap was a long-lived footwall high, the prospectivity of which was enhanced by Variscan folding and uplift, leading to the truncation (subcrop) of Lower Carboniferous reservoirs beneath the Base Permian Unconformity. Its drape (supra-crop) by Upper Permian (Zechstein Super Group) evaporites creates the seal. The complexity of its overburden means that an accurate picture of the Breagh structure only emerges after accurate depth-conversion that takes the effects of the Mesozoic graben into account. Pronounced easterly tilting during the Cenozoic affected the area and controlled gas migration into the structure from palaeostructures lying to the east. However, evidence that Breagh is not filled to spill point (underfill) suggests that charge limitation remained an issue. The study demonstrates that a poorly-documented and under-explored Lower Carboniferous play exists in Southern North Sea, which relies upon careful structural mapping and basin modelling to be undertaken for the play to be understood and its further potential to be realized. Thematic collection: This article is part of the Under-explored plays and frontier basins of the UK continental shelf collection available at: https://www.lyellcollection.org/cc/under-explored-plays-and-frontier-basins-of-the-uk-continental-shelf

The Cygnus Field, Blocks 44/11a and 44/12a, UK North Sea

Abstract The Cygnus Field is located in Blocks 44/11a and 44/12a of the UK Southern North Sea. The field was first discovered in 1988 as a tight lower Leman Sandstone Formation gas discovery by well 44/12- 1. After the licences had sat idle for several years, GDF Britain (now Neptune E&P UK Ltd) appraised the field from 2006 to 2010. During the appraisal phase, the lower Leman Sandstone was found to be of better quality than first discovered and the gas-bearing lower Ketch Member reservoir was also encountered. The field development was sanctioned in 2012. The field has been developed from two wellhead platforms targeting Leman Sandstone and Ketch Member reservoirs. Five main fault blocks have been developed, with two wells in each fault block planned in the field development plan. The wells are long horizontal wells completed with stand-alone sand screens. At the time of writing, the production plateau is 320 MMscfgd (266 MMscfgd when third-party constraints apply), producing from nine wells with the final production well to be drilled.

The Hewett Field satellites: Big Dotty, Little Dotty, Deborah, Della, Dawn and Delilah, Blocks 48/29a, 48/30a, UK North Sea

Abstract Six satellite fields have been developed through the Hewett Field facilities: Big Dotty, Little Dotty, Deborah, Della, Dawn and Delilah. Little Dotty has produced from both the Leman Sandstone Formation (LSF) and Bunter Sandstone Formation (BSF) whilst the other satellites are exclusively LSF developments. The LSF reservoir quality exhibits a marked contrast across the Dowsing Fault Zone, which separates the inboard satellites to the SW from the outboard satellites to the NE. The inboard satellites, Big Dotty, Little Dotty and Dawn, display the best reservoir quality, reflecting their lesser depth of maximum burial. These fields share a strong aquifer, exhibited a rapid water-cut development and are now shut-in. The greater depth of maximum burial experienced by the outboard satellites, Deborah, Della and Delilah, is reflected in poorer reservoir quality along with weaker aquifers that are also more compartmentalized. These remain in production and will achieve higher recovery factors. Big Dotty was developed from a wellhead platform whereas the other fields were developed as subsea tie-backs. Collectively, these satellite fields have produced some 0.9 tcf of gas, playing an important strategic role in offsetting the production decline in the Hewett Field and extending the life of the asset.

The Babbage Field, Block 48/2a, UK North Sea

Abstract The Babbage gas field was discovered in 1988 by exploration well 48/2-2 which drilled into the Permian-age lower Leman Sandstone Formation below a salt wall. Seismic imaging is compromised by the presence of this salt wall, which runs east–west across the southern part of the structure, creating uncertainties in depth conversion and in the in-place volumes. Pre-stack depth migration with beam and reverse time migrations appropriate for the complex salt geometry provided an uplift in subsalt seismic imaging, enabling the development of the field, which is located at the northern edge of the main reservoir fairway in a mixed aeolian–fluvial setting. Advances in artificial fracturing technology were also critical to the development: in this area, deep burial is associated with the presence of pore-occluding clays, which reduce the reservoir permeability to sub-millidarcy levels. The Babbage Field was sanctioned in 2008, based on an in-place volume range of 248–582 bcf; first production was in 2010. It produces from five horizontal development wells that were artificially fracced to improve deliverability of gas from the tight matrix. None of the wells has drilled the gas–water contact, which remains a key uncertainty to the in-place volumes, along with depth-conversion uncertainty below the salt wall.

The Tolmount Field, Block 42/28d, UK North Sea

Abstract The Tolmount Field is a lean gas condensate accumulation located in Block 42/28d of the UK Southern North Sea. The field was discovered in 2011 by well 42/28d-12, which encountered good-quality gas-bearing reservoir sandstones of the Permian Leman Sandstone Formation. The discovery was appraised in 2013 by wells 42/28d-13 and 42/28d-13Z, which logged the gas–water contact on the eastern flank of the field. The Tolmount structure is a four-way, dip-closed, faulted anticline, orientated NW to SE. The reservoir comprises mixed aeolian dune and fluvial sheetflood facies deposited within an arid continental basin. Dune sands display the best reservoir properties with porosities around 22% and permeabilities exceeding 100 mD. Only minor diagenetic alteration has occurred, primarily in the form of grain-coating illite. Superior reservoir quality is observed at Tolmount compared to adjacent areas, due to the preservation of dune facies, a hypothesized early gas emplacement and a relatively benign burial history. Current mapped gas initially-in-place estimates for the field are between 450 bcf and 800 bcf, with an estimated recovery factor between 70 and 90%. An initial four-well development is planned, with first gas expected in 2020.

Chiswick and Kew fields, Blocks 49/4a, 49/4b, 49/4c, 49/5a and 49/5b, UK North Sea

Abstract The Chiswick Field is a Carboniferous gas field located in UK Blocks 49/4a and 49/4b in the Southern North Sea, approximately 18 km NW of the Markham Field, close to the UK–Netherlands median line. The Kew Field is situated approximately 3 km NE of the Chiswick Field. The Kew structure is a NW–SE-trending horst separated from the Chiswick Field, a large anticlinal domal structure, by a major NW–SE fault and a structural low. The productive reservoir units are Carboniferous (Westphalian A and B) fluvial sandstones. Both fields are situated on the eastern edge of the Silverpit Basin (part of the Southern Permian Basin). The initial exploration drilling had Leman Sandstone Formation as the primary objective, but the first wells encountered a tight Permian reservoir with gas-bearing Carboniferous reservoirs, subsequently appraised and developed. The current estimate for the gas initially in place of Chiswick and Kew is respectively 687 bcf and 85 bcf in the Carboniferous reservoir. The fields to date (Q4 2018) have produced respectively 220 bcf and 33 bcf sales gas. Gas recovery is through natural depletion from hydraulically fractured, horizontal development wells.

The Carrack Field, Blocks 49/14b, 49/15a and 49/15b, UK North Sea

Abstract The Carrack Field, located in the Southern North Sea Blocks 49/14b and 49/15a, has of the order or 15 bcm (530 bcf) gas initially in place and is operated by Shell UK Ltd. The field consists of a pop-up structure in the south of the field and extends to the north with a gently-dipping monoclinal structure. The reservoir comprises sandstones of the Permian Silverpit and Leman Sandstone formations, which contain c. 85% of the in-place resources. The quality of the reservoir decreases rapidly to the north. Gas is also produced from Carboniferous sandstones of late Duckmantian (Westphalian B)–Bolsovian (Westphalian C) age. Initially, the field was in pressure communication both laterally and vertically with a single gas–water contact. During production time, however, the three main fault blocks behaved independently, and decimetre-thick shale intervals acted as vertical baffles between the sandstone units. The Carrack Field has been in production since 2003 and is developed by a single platform with seven mainly deviated wells. The current production rate is c. 0.7 MMm 3 /day (25 MMscfgd). Until the end of field life in the 2030s, the field is expected to produce gas of the order of a few bcm. The main remaining opportunity is the undeveloped Carrack West compartment.

The Sean fields, Block 49/25a, UK North Sea

Abstract Block 49/25a contains the Sean gas fields, Sean North, Sean South and Sean East – collectively known as the Greater Sean area and discovered in 1969. The fields are located in the Southern Gas Basin, about 15 km SE of the Indefatigable gas field. Approximately 1.1 tcf of gas is trapped in a series of fault-bounded dip closures consisting of Permian sandstones belonging to the Leman Sandstone Formation (Rotliegend Group). The reservoir is overlain by evaporites of the Late Permian Zechstein Group. The fields are characterized by excellent Leman reservoir quality, and resources have increased significantly over the years. The reservoir largely behaves as a well-connected tank, which has resulted in high recovery factors (>90%). In 2015, Oranje-Nassau Energie UK Ltd (ONE) took over operatorship of the field through purchasing the rights of both Shell and Esso, giving ONE a 50% operated interest together with SSE E&P UK Ltd (SSE). In 2017, an infill well (SSPD05) was drilled by ONE to test a pop-up structure situated between Sean North and Sean South. The well found, as expected, partially depleted reservoir but has proven to accelerate production and add incremental reserves to the field.

The Hewett Field, Blocks 48/28a, 48/29a, 48/30a, 52/4a and 52/5a, UK North Sea

Abstract The Hewett Field has been in production for some 50 years. Unusually for a Southern North Sea field in the UK Sector, there has been production from several different reservoirs and almost entirely from intervals younger than the principal Leman Sandstone Formation (LSF) reservoir in the basin. Some of these reservoirs are particular to the Hewett area. This reflects the location of the field at the basin margin bound by the Dowsing Fault Zone, which has influenced structural evolution, deposition and the migration of hydrocarbons. The principal reservoirs are the Permo-Triassic Hewett Sandstone (Lower Bunter), Triassic Bunter Sandstone Formation (BSF) (Upper Bunter) and Permian Zechsteinkalk Formation. There has also been minor production from the Permian Plattendolomit Formation and the LSF. Sour gas is present in the BSF only. Several phases of field development are recognized, ultimately comprising three wellhead platforms with production from 35 wells. Gas is exported onshore to Bacton, where the sour gas was also processed. Peak production was in 1976 and c. 3.5 tcf of gas has been recovered. Hewett has also provided the hub for six satellite fields which have produced a further 0.9 tcf of gas. It is expected that the asset will cease production in 2020.

The Ensign Field, Blocks 48/14a, 48/15a and 48/15b, UK North Sea

Abstract The Ensign Field is located in UK offshore licence Blocks 48/14a, 48/15a and 48/15b. The field is located 100 km east of the Humberside coast within the Sole Pit area of the Southern North Sea. The reservoir consists of sandstones of the Permian Rotliegend Group (Leman Sandstone Formation). Reservoir quality has been impacted by diagenesis during deep burial, whereby illitization has reduced permeability to sub-millidarcy scale. The field has been developed with two horizontal production wells, both completed with five hydraulic fracture stages. First gas from the field was achieved in 2012 via the Ensign normally unmanned installation and exported through the Lincolnshire Offshore Gas Gathering System. The field is compartmentalized by multiple regional-scale De Keyser fault zones. A heterogeneous natural fracture network exists with only a limited contribution to flow. Well performance and ultimate gas recovery have been lower than originally anticipated due to sub-optimal completions and a higher degree of compartmentalization than originally expected. The volume of gas that is connected to the wells is limited by low-offset faults, which have been identified by integrating long-term production data, and core, log and reprocessed seismic data. Production ceased in 2018 when the original export route was decommissioned.

The Juliet Field, Block 47/14b, UK North Sea

Abstract The abandoned Juliet gas field is a small, highly compartmentalized, accumulation situated south and east of the Amethyst Gas Field. It was discovered in 2008 by well 47/14b-10 and flowed first gas on 5 January 2014. The field consists of at least two culminations within a very low-relief east–west-orientated fault-bounded anticline. The reservoir comprises aeolian sandstones of the Permian, Rotliegend Group, Leman Sandstone Formation. Reservoir quality varies from good to moderate, with a high production rate achieved from horizontal wells. Seismic time-to-depth conversion is affected by Quaternary seabed channels, chalk burial history and a rapid thickening in the Basalanhydrit Formation located over the east of the field, associated with the edge of the Zechstein Basin. Gas-in-place at pre-development was expected to be 105 bcf, with reserves of 67 bcf. The field was developed using two horizontal wells and a subsea tie-back to the Pickerill Field, 22 km to the east. Since development, the field appears to be more compartmentalized than initially expected.

The Viking Fields, Blocks 49/11d, 49/12a, 49/16a, 49/16c, 49/17a, UK North Sea

Abstract The Viking Fields were a gas development in the UK Southern North Sea, c. 130 km east of the Lincolnshire coast in 30 m water depth and covering Blocks 49/11d, 49/12a, 49/16a, 49/16c, 49/17a. The area comprised the Viking A, B, C, D and E Fields. The Viking Fields were discovered in 1965 and started producing in 1972. The development was in two phases from 1971 to 1994 and from 1995 to 2000; the latter phase included the ‘Phoenix development’. The fields continued to produce until September 2015. Plugging and abandonment of the Viking Field wells was complete in 2017, with final decommissioning planned for 2021. The Viking Fields have produced 3.3 tcf of gas from the Rotliegend Group, Leman Sandstone Formation, aeolian-dominated reservoir rocks with a porosity range of 7–25% and average permeability of >100 mD. The Viking reservoirs are impacted by NE--SW De Keyser faults which often delineate and compartmentalize the reservoirs. The final recovery factor for the Viking Fields was 90%. This paper summarizes the geology, development history and performance of these legacy assets.

The evolution of the Dowsing Graben System: implications for petroleum prospectivity in the UK Southern North Sea

Upper Permian (Zechstein Supergroup) evaporites have a major control on structural styles and prospectivity in the UK Southern North Sea (SNS). They form the regional super-seal for the main Rotliegend Group (Leman Sandstone Formation) reservoir play fairway immediately beneath. The evaporites have highly variable thicknesses due to the syndepositional basin architecture, differential loading and post-depositional deformation through diapirism and salt withdrawal. The halokinetic activity leads to touchdown (welding) of the supra-salt section onto the sub-salt strata and the development of narrow (up to 15 km-wide) graben systems. The interpretation and depth conversion of well-calibrated, high-quality, 3D post-stack time-migrated (PSTM) seismic data along the southwestern margin of the basin show that a NW–SE-striking elongate extensional Dowsing Graben System transects the area. The graben is defined by a series of large, overlapping, en echelon listric growth faults, with oblique secondary planar faults, which sole-out on two main (deep and shallow) décollement levels in the Zechstein Supergroup and the Middle Triassic Röt Halite Member. Whilst its initial formation was related to Mesozoic extension, the graben system also displays a contractional overprint resulting from regional compression and structural inversion during the Cenozoic. Detailed mapping of the Zechstein Supergroup has revealed that the evolution of the extensional system was influenced by the ESE–WNW-striking anhydrite–carbonate Zechstein shelf-margin. The occurrence of variable-thickness, low-velocity sediments within the graben impacts seismic imaging and depth conversion, leading to prospective structures being overlooked; something that has implications for prospectivity in the SNS and other evaporite basins where similar graben occur.

Upper Permian Zechstein Supergroup carbonate-evaporite platform palaeomorphology in the UK Southern North Sea

Abstract Seismic interpretation, geological mapping and depth conversion of the Zechstein Supergroup (Z2 cycle), using high-quality well-calibrated three-dimensional (3-D) seismic, has revealed the complex palaeomorphology of a deeply-buried ancient carbonate shelf-margin on the southwestern margin of the Southern Permian Basin. The new mapping shows that the margin comprises a series of corrugated embayments and promontories which extend up to 5 km (3 mi) into the basin and locally have a palaeobathymetric relief of >200 m (650 ft). Well calibration across the margin demonstrates a strongly bipartite lateral thickness distribution between a high velocity anhydrite-dominated shelf and a lower velocity halite-dominated basin. Strong lateral and vertical velocity variations in the Upper Permian Zechstein Supergroup are known to have major impacts upon seismic imaging and depth conversion in the SPB. The resulting uncertainty remains one of the major challenges when interpreting and assessing the prospectivity of the underlying Upper Permian, Rotliegend Group (Leman Sandstone Formation) reservoirs in the UK Southern North Sea. An understanding of the Zechstein shelf edge's 3-D physiography and its velocity variation has implications for the delineation of traps containing the prospective reservoirs that lie below. Recognition of the complexity and effects of this shelf-margin contributed to the recent Juliet Discovery whose position outside of the presently defined Rotliegend Group play fairway suggests that prospectivity is more extensive along the basin margin than previously thought. As such, the work provides a means by which to identify and delineate new structures and extend the life of this mature yet prolific gas province.

Petroleum geology of the Cygnus gas field, UK North Sea: from discovery to development

Abstract The Cygnus Field, operated by ENGIE E&P UK Limited, is located in UK Southern North Sea blocks 44/11 and 44/12. The reservoir comprises sandstones of the Permian Leman Sandstone Formation and Carboniferous Ketch Formation. Cygnus was first drilled in 1988 by well 44/12-1, which encountered gas shows in sandstones in the Leman Sandstone Formation whilst targeting a Carboniferous objective. The initial evaluation indicated the presence of poor-quality reservoir with conventional log analysis indicating high water saturations. Further appraisal activity ceased until 2002 when a group led by ENGIE E&P UK Limited were awarded the licence in the 20th round having recognized the missed pay potential. Through appraisal drilling, a second reservoir (the Carboniferous Ketch Formation) was discovered and the Leman Sandstone Formation was proven to be capable of achieving stabilized flow rates greater than 30 MMscf/d. The Cygnus discovery now proves that a northern-sourced Leman Sandstone Formation play fairway exists, establishing an extension of the Rotliegend play to the northern feather edge of the Southern Permian Basin. The Cygnus Field's estimated ultimate recoverable volume is forecast to be 760 Bscf, making it the largest field discovered in the UK Southern North Sea in the last 30 years.

Unlocking stranded resources in naturally fractured reservoirs using a novel approach to structural reconstructions and palaeostress field modelling: an example from the Hoton field, southern North Sea, UKCS

Abstract Remaining resources in mature basins, such as the southern North Sea (SNS), are often associated with complex or unconventional reservoirs. Unlocking the value of these resources requires non-conventional approaches to the description and the development of the reservoir. Originally developed as a conventional reservoir, the Hoton field in the SNS delivers economic rates from a tight and fractured Lower Leman Sandstone. The northern part of the field is developed via a trilateral producer, but the field's southern half, which appraisal drilling showed to consist of poor-quality rock, was deemed too tight for development. Roughly 40% of the field's resource of dry gas lies within the southern part of the field with no plans to develop it. A reassessment of the southern area's potential using geomechanical tools suggests that it also could deliver commercial well rates, similar to those experienced in the northern area of the field. A combination of structural restorations using Dynel2D and forward deformation modelling using Poly3D produces palaeostress predictions, which are used to constrain a discrete fracture network model. From these, well profiles are generated that suggest that a development well into the southern part of the field can recover about half of the currently stranded resource.

Development of Key Performance Indicators for CO2 Storage Operability and Efficiency Assessment: Application to the Southern North Sea Rotliegend Group

This paper outlines the development of a methodology which can be used to produce key performance indicators for operability and efficiency of a CO2 storage site. The methodology is based on the premise that individual geological formations and their characteristics can be assessed on the basis of their depositional and tectonic setting and more recent reservoir/site history using hydrocarbon exploration and development data. The methodology is illustrated for a candidate storage reservoir in the Rotliegend Leman Sandstone Formation of the UK Southern North Sea.