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Equinor will sell its nonoperated equity position in the Corrib gas project in Ireland to Vermilion Energy for $434 million. The sale of Corrib results in Equinor no longer having an active business presence in Ireland, after also deciding to withdraw from an early- phase offshore wind project in the country. The Corrib field started production in 2015 and is located 83 km off Ireland's northwest coast in water depths of almost 350 m. The equity gas volumes to Equinor for 2021 are estimated at around 58 MMcf/D. As part of the transaction, Equinor and Vermilion have agreed to hedge approximately 70% of the production for 2022 and 2023 and have also agreed a contingent payment that will be paid on a portion of the revenue if European gas prices exceed a given floor level.
Thatcher, Alexander (Oilfield Production Consultants - Aberdeen) | Colleran, Peter (Nephin Energy Limited) | Roberts, William (Consultant) | Johnson, Piers J. (Oilfield Production Consultants - London)
Abstract This paper presents an analysis of the Corrib field surveillance dynamic pressure and rate data. The Corrib field, on production since December 2015, is a gas reservoir developed with six wells. The field static gas initially in place (GIIP) is around 1.2 Tcf of dry gas and the reservoir is comprised of a complex heterogeneous sandstone consisting of a high net to gross sequence of low sinuosity braided fluvial channel, sheet sand, playa and sandflat facies of varying reservoir quality (from single to hundreds of millidarcys) with an abundance of mapped faults. The dynamic reservoir analysis approach used in this study is based on a form of pressure-rate deconvolution that has been presented in an earlier paper SPE-195441 for the Tamar field, Israel. The pressure transient analysis (PTA) software that implements this analysis capability handles both singlewell and multi-well analysis problems. From a preliminary review of Corrib field dynamic behavior, it was concluded that this field data can be analyzed using single-well pressure-rate deconvolution applied to the data of each reservoir well separately. This contrasts with the Tamar field that required a true multiwell deconvolution analysis approach. Different approaches in these cases are dictated by the differences in reservoir architecture, geology, offtake strategy and the character of connectivity across these two fields. There are several pressure-rate deconvolution algorithms implemented in different PTA software tools used in the industry. All these algorithms implement a form of automatic regression and are sensitive to the quality of pressure and rate data that serve as input into the deconvolution algorithm. These automatic algorithms are often not robust enough to be used with surveillance type data acquired during long term production operations. The deconvolution approach used in this work is not automatic and, as a result, the deconvolution results are not as sensitive to the data quality. Rather, it relies on specialized software that facilitates manual reconstruction of constant rate drawdown responses. This human approach in combination with specialized software allows an engineer not to just reconstruct a drawdown response but to "explore" the pressure and rate data to develop significant insights of the dynamic reservoir behavior. This deeper understanding is an additional advantage over automated techniques and is the purpose of reservoir analysis. The Corrib field analysis discussed in this paper is a demonstration of what can be achieved using this combination of human intelligence and specialized software tools. Demonstration of the workflow used for manual reconstruction of deconvolved response functions and the role of the specialized software used that implements this workflow is explained. In the course of this reconstruction, an "exploration" process of trying to reconstruct the transient pressure behavior reflected in the data is engaged/utilized. Once reconstructed, this response is interpreted in terms of reservoir and well properties. The end result of this investigation is a deep understanding of the Corrib gas field dynamic behavior not easily obtained from conventional PTA methods. For example, it shows that early production data clearly exhibit signs of interference between wells. However, once the field production drops off the plateau period and the well production starts to decline, the six producing wells dynamically divide the reservoir into separate drainage areas and the well interference in a way "disappears" - the wells behave as if each of them produces from its own drainage compartment. This allows pressure rate deconvolution on a single-well basis, based on each compartment instead of using multi-well deconvolution on the field as a whole. The pore volume of each such compartment is reflected in the late time pressure behavior of the respective drawdown response associated with the well data. The sum of these individual pore volumes per well in the field yields the total pore volume connected to the wells that is supported by the reservoir dynamic behavior. These insights are reinforced by the use of synthetic models to provide clarity and understanding of the drainage compartment theory used during Corrib analysis.
Abstract Frontier Exploration Licence 7/97 is located 115km offshore north-west Ireland and directly overlies the Erris Ridge. The ridge is an enigmatic, narrow, segmented, NE-SW orientated structural high which lies between the Erris Basin to the east and the Irish Rockall Trough to the west and which, to date, remains un-drilled. Seismic data quality across the Erris Ridge is typically poor and correlation with the sparse offset well database is challenging. Zones of poor seismic imaging are associated with combinations of complex shallow volcaniclastics, possible intrusive features and large-scale Tertiary channels/entry points which overlie older strike-slip zones and segment the ridge along its length. Displaying considerable complexity and structural variation along strike, seismic based interpretations provide models ranging from a shallow basement horst to preservation of significant thicknesses of Paleozoic and Mesozoic sediments. Recent work by Eni identifies the potential for prospective section to be preserved on the Erris Ridge resulting in two large prospects, Fiachra and Conn, and a number of leads being identified. The Fiachra Prospect is a large fault assisted four-way dip closure situated within a crestal location on the Erris Ridge and forms the focus of an exploration well planned for 2010. An early Triassic sandstone play (Sherwood Sandstone Group equivalent) is prognosed as the primary reservoir target interval, although several secondary targets also exist. After an intensive evaluation programme the critical geological risk remains modelling the presence of sedimentary section with reservoir potential in areas where the quality of seismic data is very poor. However, it is concluded that Licence 7/97 possesses good potential for deepwater frontier exploration; the Corrib gas field to the south of the licence area and the Dooish gas discovery to the north indicate the potential for a favourable location within an effective petroleum system. Introduction Frontier Exploration Licence (FEL) 7/97 is located on the Irish Atlantic Margin, approximately 115km offshore northwest of Ireland in water depths spanning 200m to 2000m (Figure 1). The licence extends over eight blocks; 11/20, 11/23 (part), 11/24, 11/25, 11/28 (part), 12/11 (part), 12/12 (part), and 12/16 (part), covering an area of 1327.66km and is located over the NE-SW trending Erris Ridge which separates the Rockall Trough to the west from the Erris Basin to the east. Eni acquired full operatorship of FEL 7/97 in 2001 and has since undertaken an extensive evaluation programme in order to assess the prospectivity of the licence area and support the decision to commit to the drilling of a frontier exploration well on the Fiachra prospect. Accordingly, the prime focus of exploration activity has centred on the Erris Ridge and, in particular, the maturation of the Fiachra prospect. Critical factors determining prospectivity across the Erris Ridge are related to structural evolution and the age and thickness of potential reservoir quality stratigraphic section preserved across the poorly imaged central region of the ridge, both of which have been subjects of discussion (e.g. Cunningham and Shannon, 1997; Chapman et al., 1999). This uncertainty is difficult to address through conventional seismic acquisition as a result of poor data quality predominantly influenced by shallow, indurated, Paleogene volcaniclastic deposits which are widespread within the licence area.
Introduction Summary Accurate measurement of the temporal and spatial variation of uplift and denudation can improve our understanding of the way in which mountain building and mantle convection modify the Earth’s surface (Mackay & White, 2006). In this project, we focus on the Slyne basin, offshore Ireland, which has been affected by rift flank and epeirogenic uplift. Measuring uplift directly is generally impossible because reference levels are usually destroyed or at least modified by processes of erosion. A way to address this problem is to evaluate the magnitude and distribution of denudation at regional unconformities. Most common methods used exploit the thermal or mechanical properties of rocks, such as apatite fission track, vitrinite reflectance, sonic velocity modelling, but they all have the disadvantage to be restricted to boreholes locations (Walford & White, 2005). In addition there is often a large scatter in these sparsely distributed measurements. We show in this study that inversion of seismic velocity profiles from seismic reflection datasets can be a useful tool to spatially constrain the distribution and the magnitude of denudation. The subject is very important to oil exploration in the region in order to calibrate maturity models. The aim of this project is to calculate the magnitude of denudation that occurred in the Slyne basin. The Slyne basin lies about 60 km off the northwest coast of Ireland (Dancer & Piller, 2001), with water depth ranging between 150 – 500 m. As part of a series of extensional basins trending NNE – SSW, it is a half graben cut by transfer faults, dividing it into Northern, Central and Southern parts (Scotchman & Thomas, 1995). Rifting began during the Permo-Triassic and was probably related to the opening of the North Atlantic ocean (Dancer et al., 1999). To the North outside our immediate study region of the Corrib field Tertiary lavas and Cretaceous chalks subcrop at the seabed and render seismic imaging difficult. Dancer et al. (1999) have documented the sediment fill of the Slyne basin, from the wells 18/20-1, 27/5-1 and 27/13- 1. In our specific study zone (Fig. 1), it appears that Neogene sands and clays overlay unconformably the Middle to Upper Jurassic strata (Oligo-Miocene unconformity on Fig. 2). In other parts, the Cretaceous calcareous clays are discordant upon Jurassic layers. The Jurassic and Triassic sediments overlie the Permian evaporitic sequence and the Carboniferous basement. The Jurassic sediments have undergone subsidence and maturation. They were uplifted and eroded between the Jurassic and the Cenozoic. seismic velocity data Method: estimating magnitude of denudation from Seismic velocity is controlled by the mineralogy, porosity, density, pore fluid composition and properties, pressure and depth (e.g. Sheriff & Geldart, 1983) of the imaged succession. However, the porosity of the medium is often the primary control factor on the seismic velocity because the sonic velocity of the pore fluid is much lower than that of solid sediments grains (Mackay & White, 2006). So, by measuring the sonic velocity of a sedimentary rock, we can evaluate its porosity.
Abstract A working window of opportunity only presents itself from April to mid-September in the turbulent Atlantic waters off the northwest coast of Ireland. When this window opened in Spring 2006, Shell E&P Ireland Ltd began operations to evaluate newly acquired assets in the Corrib field dry-gas subsea development. Prior to acquisition, five wells had been placed in suspension, pending construction of the necessary subsea and onshore infrastructure. Shell had previously determined that only three wells were viable candidates for completion during the current season and commenced operations when the S711 semi-submersible arrived on location in April. The clock started ticking on favorable weather and time quickly became a crucial constraint issue. The project hit a critical mark when a leak was discovered in the 9–5/8 in. production casing on one of the early wells entered. With time running out, Shell approached Enventure to engineer a practical solution that was required within a period of six weeks. Possible solutions for recovery were identified and analyzed before the project management team decided on using solid expandable technology. The solution for this well needed to deliver a production casing string that effectively sealed off the hole. To accomplish this requirement with expandable tubulars, Shell decided to use the Enventure system elastomers for the gas-tight integrity, which required qualification. In approximately six weeks, Enventure and Shell planned and implemented the appropriate tests, coordinated logistical maneuvers to expedite expansions to create the test specimen for qualification and successfully installed the actual system in the production well. This paper will discuss the process used to bring the project to fruition within a tight timeframe. Details will include issues considered, ramifications of possible options, challenges of the operating conditions and circumstances and content and results of the qualification program. This paper will also discuss the philosophical approach of generating a workflow to successfully achieve the stated goals in a short amount of time. Introduction In June 2006, Shell encountered a leak in the 9–5/8 in. production casing in one of its West Atlantic, deepwater subsea wells. The dry gas well is capable of producing in excess of 100 million standard cubic feet per day. The leak, identified after taking the well out of suspension, disappointed the project team as progress to run completion and ultimately put the well in production came to an abrupt halt. After eliminating the possibility of it being in the liner lap, the leak was chased to approximately 1,500m (~4,920 ft) using a DLT packer. In order to progress the campaign, Shell temporarily suspended the well to decide whether to attempt to regain integrity of the production casing or put the well in long term suspension for possible abandonment. After putting the well into suspension, management considered the following four options to address the situation:Abandon and re-drill the well Cut and pull the 9–5/8 in. casing Use a tie-back liner solution Install a solid expandable cased-hole liner system Because of time restrictions and the lack of equipment availability with three of the options, Shell chose the solid expandable tubular solution that could be tested, delivered and installed in the timeframe and provide the most robust engineering solution. Although Shell had decided on a definitive approach to the casing leak, several issues needed to be addressed before the solid expandable solution could be implemented. The elastomer technology on the expandable liner selected, specifically Enventure 's 7–5/8 x 9–5/8 in. solid expandable system, had been used in similar scenarios but was not qualified to Shell standards. Another issue identified was the lack of gas-tight connections for any expandable casing. Also, several load cases were outside the expandable envelope. Shell and Enventure personnel used innovative engineering to confront the obstacles and to successfully resolve the technical challenges.