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SeisRAFT: A recurrent deep learning network for 4D seismic registration and CO 2 storage monitoring
Sleipner 26 years: how well-established subsurface monitoring work processes have contributed to successful offshore CO 2 injection
Chapter 9. Application of sequence stratigraphy to the evaluation of selected North Sea Jurassic hydrocarbon fields and carbon capture, utilization and storage (CCUS) projects
Abstract The application of sequence stratigraphic concepts and methods augments the efficient development of North Sea hydrocarbon fields with Jurassic reservoirs. In particular, the approach provides enhancements to the development of robust reservoir zonations, more accurate assessments of the extent and continuity of reservoir zones and flow units, clearer identification and prediction of the most productive reservoir intervals, improved understanding of field-wide pressure barriers or baffles to fluid flow, and enhanced reservoir models. In addition, carbon capture and storage (CCS) projects in Jurassic rocks will benefit from the adoption of a sequence stratigraphic approach by enhancing the understanding of storage unit architecture, connectivity and top seals. In this chapter, these applications are discussed with reference to around 20 case studies from the North Sea Basin.
Seeing through the CO 2 plume: Joint inversion-segmentation of the Sleipner 4D seismic data set
Capillary pressure equilibrium theory mapping of 4D seismic inversion results to predict saturation in a gas-water system
Reservoir multiparameter prediction method based on deep learning for CO 2 geologic storage
Comparison of shale depth functions in contrasting offshore basins and sealing behaviour for CH 4 and CO 2 containment systems
An optimized staggered-grid finite-difference operator for seismic wave simulation in poroelastic media
Competitive Effects of Permeability and Gravity on the Drying-Out Process during CO 2 Geological Sequestration in Saline Aquifers
Seismic low-frequency shadows and their application to detect CO 2 anomalies on time-lapse seismic data: A case study from the Sleipner Field, North Sea
Quantification of solubility trapping in natural and engineered CO 2 reservoirs
Bayesian rock-physics inversion: Application to CO 2 storage monitoring
The Blane Field, Block 30/3a, UK North Sea
Abstract The Blane Field is located in the central North Sea in Block 30/3a (Licence P.111), approximately 130 km SE of the Forties Field, in a water depth of 75 m (246 ft). It straddles the UK/Norway median line with 82% of the field in the UK and 18% in Norway. Blane produces undersaturated oil from the Upper Forties Sandstone Member of the Sele Formation and contains good quality light oil within a four-way structural closure; it has a hydrodynamically tilted original oil–water contact. The field stock-tank oil initially in place estimate is 93 MMbbl with an expected ultimate recovery of 33 MMbbl. Blane first oil was achieved in September 2007. The field has been developed by two horizontal producers located on the central crest of the field supported by a water injector drilled on the NW flank. Oil production peaked at c. 17 000 bopd in 2007 and the field is currently in decline. By the end of 2018 production was c. 3000 bopd with 55% water-cut. Cumulative oil production to the end of 2018 was 26.6 MMbbl.
The Alba Field, Block 16/26a, UK North Sea
Abstract The Alba Field is a relatively heavy oil accumulation lying in an Eocene deep-water channel complex in Block 16/26a of the Central North Sea. With an estimated 880 MMbbl in place, the reservoir is characterized by thick, high net/gross sands with excellent reservoir properties and rock physics favourable for seismic property detection. The field has been developed by horizontal production wells, with pressure support provided by seawater injectors. After 24 years of production, more than 427 MMbbl have been recovered. Over the course of the development, the results of development drilling and improved reservoir imaging from seismic have revealed greater reservoir complexity than anticipated at sanction. The highly irregular reservoir geometry is likely to reflect the internal stacking patterns of channel elements within the channel complex that are locally overprinted by post-depositional remobilization. This increased reservoir complexity has required more wells to effectively drain the expected volumes. Despite this, recovery has exceeded estimates from the initial field development plan, reflecting an extremely efficient waterflood. 4D seismic spectacularly images extensive sweep away from injectors and excellent reservoir connectivity. Throughout the development, the application of seismic technologies has been a key enabler for effective reservoir management and, looking forward, maximizing value.
Abstract The Lower Cretaceous Britannia Field development is one of the largest and most significant undertaken on the UK Continental Shelf. Production started in 1998 via 17 pre-drilled development wells and was followed by a decade of intensive drilling, whereby a further 40 wells were added. In 2000 Britannia's plateau production of 800 MMscfgd supplied 8% of the UK's domestic gas requirements. As the field has matured, so too has its development strategy. Initial near-field development drilling targeting optimal reservoir thickness was followed by extended reach wells into the stratigraphic pinchout region. In 2014 a further strategy shift was made, moving from infill drilling to a long-term compression project to maximize existing production. During its 20-year history the Britannia Platform has undergone numerous changes. In addition to compression, production from five satellite fields has been routed through the facility: Caledonia (2003), Callanish and Brodgar (2008), Enochdhu (2015) and Alder (2016). A new field, Finlaggan, is due to be brought through Britannia's facilities in 2020, helping to maximize value from the asset for years to come. As Britannia marks 20 years of production it has produced c. 600 MMboe – surpassing the original ultimate recoverable estimate of c. 570 MMboe – and is still going strong today.
Abstract The Burghley Field is a Paleocene oil field located in Block 16/22 on the UK Continental Shelf about 8.5 km NE of the Balmoral Field, in a water depth of c. 143 m. Burghley produces undersaturated oil from sandstones of the Maureen Formation. It comprises a low relief four-way dip-closed structure located on the SE end of the Fladen Ground Spur. The field was discovered in 2005 by well 16/22-7. Overall nine well penetrations were drilled prior to the commitment to develop the field. The Burghley Field was brought on-stream in October 2010 as a single subsea horizontal well development tied back to the Balmoral floating production vessel. The current estimate for oil in place is c. 20 MMbbl for the entire field, with approximately 12 MMbbl in the core area where the development well is located. The expected ultimate recovery is approximately 5.65 MMbbl.
The Enoch Field, Block 16/13a, UK North Sea
Abstract The Enoch Field is located in the South Viking Graben and straddles the UK/Norway median line with 80% of the field in the UK and 20% in Norway. Enoch produces undersaturated oil from the Early Eocene-age Flugga Sandstone Member of the Sele Formation. Hydrocarbons have been trapped by a combination of compaction-related dip closure and sand pinchout. The current stock tank oil initially in place estimate is c. 42 MMbbl with expected ultimate recovery of 11.5 MMbbl. The field was brought onstream in May 2007 via a single horizontal subsea gas-lifted well tied back to the Brae Alpha platform. Initial oil production rates were c. 11 800 bopd. The field is currently in decline and in December 2018 production was c. 1800 bopd with 80% water-cut. Cumulative oil production to the end of 2018 was 10.581 MMbbl.
The Morag Field, Block 16/29a, UK North Sea
Abstract The Morag Field is a small oilfield underlying the Maureen Field in UK Block 16/29a. Black oil is trapped within Upper Permian, Morag Member, vuggy and fractured dolomite rafts between 9300 and 10 600 ft true vertical depth subsea. The dolomite reservoir occurs at the top of a Zechstein salt dome. Morag was discovered in 1979 by well 16/29a-A1, the first platform well drilled for the overlying Maureen Field with its Paleocene sandstone reservoir. Morag was produced via a single well (16/29a-A1) between 1991 and 1994. Three more platform wells were drilled into the Permian interval prior to Maureen Field start up but only one penetrated oil-bearing dolomite (16/29a-A2). An additional well (16/29a–A23Z) was drilled into the Morag Field in 1993. The well encountered Morag Member at virgin pressure and tested oil at high flow rate but then the well failed due to mechanical problems. Oil in place was calculated to be about 24 MMbbl in four independent fault blocks. Ultimately 16/29a-A1 delivered 2.6 MMbbl from a fault block calculated to have held 6.7 MMbbl stock tank oil initially in place.
The Role of Reactive Transport Modeling in Geologic Carbon Storage
ABSTRACT The structural evolution of the T-Block (U.K. 16/17) Brae Formation fields in the southern part of the South Viking Graben reflects a history of Late Jurassic rifting and Early Cretaceous inversion. Triassic rifting follows an inherited Caledonian trend, with Permian and Triassic depocenters to the northwest and southeast of a ridge trending north–northeast through the South Viking Graben from the area of the Thelma field. In the northern part of the area, in Trees Block (U.K. 16/12), halokinesis has created accommodation space for Middle Jurassic deposition. Further south, in T-Block, Middle Jurassic deposition does not appear to have been influenced by Caledonide structures. Rifting commenced in Trees Block in the early part of the Late Jurassic, with development of a north–south striking northern fault segment. The faulting propagated southward from the northern segment and northward from a segment to the south of T-Block, to create a relay zone opposite Thelma and Toni. At the segment centers, the fault throws are large, and the Middle Jurassic sequence dips to the west, toward the footwall. In comparison, at the Thelma relay zone, the fault displacements are much smaller, and the Middle Jurassic dips to the east. Flexural uplift and back-tilting have affected the footwall sediments and normal faults. The fault segment evolution is likely to have been a significant control on Brae sedimentation, the back-tilting of the footwalls at the segment centers funneling sediment supply into the Thelma relay zone, and footwall uplift providing emergent source areas adjacent to the developing graben. The basin morphology has been modified by postrifting thermal subsidence, increasing the eastward dip of the fault terraces. Inversion in the Early Cretaceous caused uplift of the hanging wall, creating a bulge over Thelma and Toni, and uplift on the fault adjacent to Trees Block. This inversion event is likely to be the result of oblique northwesterly compression, causing shortening and left-lateral strike-slip on the marginal faults. This event can be related to an unconformity between the Valhall and the Carrack formations, which constrains timing to the late Barremian–Aptian.