Sleipner Field Research Articles

Geomechanical Factors Affecting Geological Storage of CO2 in Depleted Oil and Gas Reservoirs

Abstract A key to the success of long-term storage of CO2 in depleted oil or gas reservoirs is the hydraulic integrity of both the geological formations that bound it, and the wellbores that penetrate it. This paper provides a review of the geomechanical factors affecting the hydraulic integrity of the bounding seals for a depleted oil or gas reservoir slated for use as a CO2 injection zone. Potential leakage mechanisms reviewed include fault reactivation, induced shear failure of the caprock, out-of-zone hydraulic fracturing, and poorly sealed casing cements in enlarged, unstable boreholes. Parameters controlling these mechanisms include the upper and lower bounds of pressure and temperature experienced by the reservoir, the orientation and mechanical properties of existing faults, rock mechanical properties, in situ stresses, and reservoir depth and shape. Approaches to mitigate the likelihood of geomechanics-related leakage include the identification of safe upper limits on injection pressures, preferred injection well locations, review of historical records for reservoir pressures, temperatures and stimulation treatments, drilling program design to mitigate rock yielding in new wells, and assessment of wellbore integrity indicators in existing wells. Introduction In order to achieve significant reductions in the atmospheric release of anthropogenic greenhouse gases, the implementation of technologies to capture carbon dioxide (CO2) and store it in geological formations will be necessary. Deep saline aquifers have the largest potential for CO2 sequestration in geological media in terms of volume, duration, and minimum or null environmental impact(1). The first commercial scheme for CO2 sequestration in an aquifer is already in place in the Norwegian sector of the North Sea, where 106 tonnes of CO2 are extracted annually from the Sleipner Gas Field and injected into the 250 m thick Utsira aquifer at a depth of 1,000 m below the sea bed(2). In light of the economic benefits of enhanced oil recovery (EOR) derived from CO2 injection in oil reservoirs(3), these types of reservoirs will be attractive CO2 injection targets and, most likely, CO2 storage in depleted oil and gas reservoirs (or in conjunction with EOR) will be implemented before CO2 storage in aquifers. An advantage of CO2 storage in depleted oil or gas fields is the fact that much of the infrastructure for fluid injection (e.g., wellbores, compressors, pipelines) is already in place. The Weyburn CO2 Monitoring and Storage Project in Saskatchewan, Canada(4) is an example of a large-scale application of EOR operations using anthropogenic CO2, in which the oil reservoir is being evaluated for subsequent use as a long-term storage zone. A key to the success of long-term storage in depleted oil and gas reservoirs is the hydraulic integrity of both the geological formations that bound it, and the wellbores that penetrate it. The initial integrity of this "bounding seal" system is governed by geological factors. A considerable amount of effort has been devoted to the development of procedures for assessing fault seal capacity in potential hydrocarbon reservoirs(5).

Demonstrating storage of CO 2 in geological reservoirs: The Sleipner and SACS projects

At the Sleipner gas field in the North Sea, CO 2 has been stripped from the produced natural gas and injected into a sand layer called the Utsira formation. Injection started in October 1996, to date nearly 8 million tonnes of CO 2 have been injected without any significant operational problems observed in the capture plant or in the injection well. The Sleipner project is the first commercial application of CO 2 storage in deep saline aquifers in the world. To monitor the injected CO 2, a separate project called the saline aquifer CO 2 storage (SACS) project was established in 1998. As part of the SACS project, 3D seismic surveying has been used to successfully monitor the CO 2 in the Utsira formation, an industry first. Repeat seismic surveys have successfully imaged movement of the injected CO 2 within the reservoir. Reservoir simulation tools have been successfully adapted to describe the migration of the CO 2 in the reservoir. The simulation packages have been calibrated against the repeat seismic surveys and shown themselves to be capable of replicating the position of the CO 2 in the reservoir. The possible reactions between minerals within the reservoir sand and the injected CO 2 have been studied by laboratory experiments and simulations. The cumulative experiences of the Sleipner and SACS projects will be embodied in a Best Practice Manual to assist other organisations planning CO 2 injection projects to take advantage of the learning processes undertaken and to assist in facilitating new projects of this type.

CO 2 underground storage for Snøhvit gas field development

This paper presents an overview of the Snøhvit LNG project operated by Statoil and includes a description of the gas fields, the development concept, the production strategy and the LNG plant. The CO 2 is separated from the well stream and is stored in an underground structure. The technology for such storage of CO 2 is considered proven by the CO 2 storage at the Sleipner field in the North Sea. The subsea concept and the lack of a huge water-bearing formation similar to the Utsira Formation in the Sleipner area resulted, however, in challenges in establishing a prudent design for the Snøhvit CO 2 injection system. This paper describes the reservoir selection process and the reservoir modelling as well as the CO 2 injection facilities. The reservoir simulations were performed by use of the extended network option in Eclipse, which makes it possible to simulate the gas production from several well clusters combined with the CO 2 injection. The paper reviews the CO 2 injection facilities including compression unit, pipeline, injection well and well control system from shore.

CO2 underground storage for Sn�hvit gas field development

This paper presents an overview of the Snøhvit LNG project operated by Statoil and includes a description of the gas fields, the development concept, the production strategy and the LNG plant. The CO 2 is separated from the well stream and is stored in an underground structure. The technology for such storage of CO 2 is considered proven by the CO 2 storage at the Sleipner field in the North Sea. The subsea concept and the lack of a huge water-bearing formation similar to the Utsira Formation in the Sleipner area resulted, however, in challenges in establishing a prudent design for the Snøhvit CO 2 injection system. This paper describes the reservoir selection process and the reservoir modelling as well as the CO 2 injection facilities. The reservoir simulations were performed by use of the extended network option in Eclipse, which makes it possible to simulate the gas production from several well clusters combined with the CO 2 injection. The paper reviews the CO 2 injection facilities including compression unit, pipeline, injection well and well control system from shore.

4D Seismic Imaging of an Injected C02 Plume at the Sleipner Field, Central North Sea

Abstract C0 2 produced at the Sleipner field is being injected into the Utsira Sand, a major saline aquifer. Time-lapse seismic data acquired in 1999, with 2.35 million tonnes of C0 2 in the reservoir, image the C0 2, plume as a number of bright sub-horizontal reflections. These are interpreted as tuned responses from thin (< 8 m thick) layers of C02 trapped beneath intra-reservoir shales. A prominent vertical 'chimney' of C0 2 appears to be the principal feeder of these layers in the upper part of the reservoir. Amplitude-thickness scaling for each layer, followed by a layer summation, indicates that roughly 80% of the total injected C0 2 is concentrated in the layers. The remainder is interpreted to occupy the feeder 'chimneys' and dispersed clouds between the layers. A prominent velocity pushdown is evident beneath the C0 2 accumulations. Velocity estimation using the Gassmann relationships suggests that the observed pushdown cannot readily be explained by C0 2 present only at high saturations in the thin layers; a minor proportion of low saturation C0 2 is also required. This is consistent with the layer volume summation, but significant uncertainty remains.

The case for underground CO 2 sequestration in northern Europe

Abstract In northern Europe numerous industrial point sources of CO 2 surround the North Sea Basin, which contains a number of viable underground sequestration opportunities. These include injection into depleted oil and gas fields and into major regional aquifers; the latter probably offering the greatest ultimate storage potential. At the Sleipner gas field, CO 2 is being injected into the Utsira Sand, a large saline aquifer. More than 6 Mt of CO 2 have currently been injected, with a projected final target of about 20 Mt. Time-lapse seismic reflection data are being used to monitor the operation and have provided clear images of the CO 2 plume and its development with time. Moreover, CO 2 volumetrics derived from the seismic data are consistent with the well injection figures. In conjunction with reservoir simulation studies, time-lapse seismic monitoring seems, therefore, to offer an effective means of predicting the future growth, migration and dispersion of the CO 2 plume. Another important aquifer, the Bunter Sandstone, stretches from Britain to Poland. In the UK sector alone, the pore volume in structural closures is equivalent to about 350 years’ worth of current CO 2 emissions from UK power generation. Industrial CO 2 sources in northern Europe are well placed to exploit these major subsurface reservoirs and European countries are technically very well equipped to use and develop this emerging technology.

Bayesian wavelet estimation from seismic and well data

A Bayesian method for wavelet estimation from seismic and well data is developed. The method works both on stacked data and on prestack data in form of angle gathers. The seismic forward model is based on the convolutional model, where the reflectivity is calculated from the well logs. Possible misties between the seismic traveltimes and the time axis of the well logs, errors in the log measurements, and seismic noise are included in the model. The estimated wavelets are given as probability density functions such that uncertainties of the wavelets are an integral part of the solution. The solution is not analytically obtainable and is therefore computed by Markov‐chain Monte Carlo simulation. An example from Sleipner field shows that the estimated wavelet has higher amplitude compared to wavelet estimation where well log errors are neglected, and the uncertainty of the estimated wavelet is lower.

Bayesian linearized AVO inversion

A new linearized AVO inversion technique is developed in a Bayesian framework. The objective is to obtain posterior distributions for P‐wave velocity, S‐wave velocity, and density. Distributions for other elastic parameters can also be assessed—for example, acoustic impedance, shear impedance, and P‐wave to S‐wave velocity ratio. The inversion algorithm is based on the convolutional model and a linearized weak contrast approximation of the Zoeppritz equation. The solution is represented by a Gaussian posterior distribution with explicit expressions for the posterior expectation and covariance; hence, exact prediction intervals for the inverted parameters can be computed under the specified model. The explicit analytical form of the posterior distribution provides a computationally fast inversion method. Tests on synthetic data show that all inverted parameters were almost perfectly retrieved when the noise approached zero. With realistic noise levels, acoustic impedance was the best determined parameter, while the inversion provided practically no information about the density. The inversion algorithm has also been tested on a real 3‐D data set from the Sleipner field. The results show good agreement with well logs, but the uncertainty is high.

Rapid spatially coupled AVO inversion in the Fourier domain

Spatial coupling of the model parameters in an inversion problem provides lateral consistency and robust solutions. We have defined the inversion problem in a Bayesian framework, where the solution is represented by a posterior distribution obtained from a prior distribution and a likelihood model for the recorded data. The spatial coupling of the model parameters is imposed via the prior distribution by a spatial correlation function. In the Fourier domain, the spatially correlated model parameters can be decoupled, and the inversion problem can be solved independently for each frequency component. For a spatial model parameter represented on n grid nodes, the computing time for the inversion in the Fourier domain follows a linear function of the number of grid nodes, while the computing time for the fast Fourier transform follows an n log n function. We have developed a 3D linearized amplitude variation with offset (AVO) inversion method with spatially coupled model parameters, where the objective is to obtain posterior distributions for P‐wave velocity, S‐wave velocity, and density. The inversion algorithm has been tested on a 3D dataset from Sleipner field with 4 million grid nodes, each with three unknown model parameters. The computing time was less than 3 minutes on the inversion in the Fourier domain, while each 3D Fourier transform used about 30 s on a single 400‐MHz Mips R12000 CPU.

Upper Cainozoic stratigraphy in the central North Sea (Ekofisk and Sleipner fields)

The investigation is based on analyses of planktonic and benthonic foraminifera and Bolboforma carried out in the uppermost Palaeogene and Neogene of the production well 2/4-C-11 (56°33' N, 3°13' E) on the Ekofisk Field and the exploration well 15/12-3 (58°14' N, 1°53' E) on the Sleipner Field. The analyses are based primarily on ditch cuttings, but in well 2/4-C-11, 49 sidewall cores and six short conventional cores were also available. Strontium isotope and paleomagnetic analyses were also carried out in well 2/4-C-11. A 420 m-thick accumulation of Lower Miocene sediments is present in the Ekofisk area. The Middle Miocene comprises approximately 180 m, and the Upper Miocene is represented by an approximately 500 m-thick interval. A hiatus is present in the Middle Miocene, and the middle part of the Middle Miocene is missing. A thin interval (approximately 120 m) of Lower Pliocene sediments is found overlying the Upper Miocene. Uppermost, a thick accumulation of Upper Pliocene-Pleistocene sediments (approximately 1000 m) is in place. More than half of this was deposited during the Pleistocene. The entire Upper Pliocene is represented in this area. This contrasts to the northern North Sea, as well as areas further north, where sediments of this epoch are partially missing in a hiatus comprising the lowermost part of the Upper Pliocene. In the Sleipner area the Lower and Middle Miocene are approximately 160 m and 180 m thick, respectively. The Upper Miocene (approximately 100 m) and the Lower Pliocene (approximately 40 m) thin from the Ekofisk towards the Sleipner Field. Uppermost, an approximately 900 m-thick succession of Upper Pliocene-Pleistocene sediments is present. Nearly two-thirds of this accumulation are Pleistocene in age.

The Sleipner Platform Accident

The Sleipner Field development in the North Sea is the key to the enormous Troll gas contract which will meet up to 10% of the western Europe’s gas demand over a period of some 30 years. The Sleipner platform alone covers the first three years of this contract, the largest multinational trade contract ever entered into by Norwegian companies. The gravity base structure (GBS) of the Sleipner A platform was a cornerstone of the Sleipner development. However, this structure suffered a major leakage and sank in the Gansfjord off Stavanger early in the morning of August 23, 1991. The failure mode described in October 1991 by two independent investigation committees is in agreement with the eyewitness observations of the accident. On that basis, the decision was taken to rebuild the concrete structure. Construction of the new platform was accomplished at an accelerated pace, reducing the construction schedule by 150 months (a 45% reduction) when compared with the first GBS.

Numerical basin modelling of the Sleipner field, North Sea

ABSTRACTBoth one‐dimensional (1‐D) and two‐dimensional (2‐D) basin modelling has been carried out in the Sleipner area in the North Sea. Thermal refraction by salt and more minor convection by fluid transport combine to provide a temperature regime which is hotter at the Sleipner East field relative to the Sleipner West field by approximately 5°C at the same sub‐surface depth. These results are obtained only with 2‐D modelling, and show that such simulations are necessary to explain the spatial variations of temperature distribution at the least.Modelling of hydrocarbon generation in the Sleipner kitchen shows that the source rocks are presently in a late gas generation state, and that a gas‐condensate is to be expected in fields draining this kitchen. Such hydrocarbon phases are encountered in the Sleipner field, confirming that the model can simulate satisfactorily hydrocarbon generation in the Sleipner area.

Quaternary stratigraphy of the fladen area, central North Sea: A multidisciplinary study

AbstractBased on detailed stratigraphic investigations on a 200.6m long core (BGS borehole No. 81/26) from the Fladen Ground area (British sector), core material from the Sleipner field (Norwegian sector) and shallow seismic profiles between the core‐sites, the following conclusions are drawn: (1) The North Sea was glaciated sometime during th elaterpart of Matuyama reversed period. A complete glacial‐interglacial‐glacial cycle is recorded in these sediments. (2) In a period of marine sedimentation in the Middle Pleistocene, a transgression‐regression cycle under boreal‐arctic regime is recorded. (3) The Fladen area has subsided between 0.9 and 0.6 m/ka through the later parts of the Quaternary (4) A major glacial event dated at between 130 and 200 ka is recorded as a thick till unit in 81/26. This till, which was deposited by ice moving from the southwest (Scotland), probably represents a period when the Scandinavian and British ice sheets coalesced in the North Sea. (5) Based on the seismic data and the stratigraphy of the Sleipner core, an ice‐free, open embayment/dry land is favoured for the central North Sea during the Late Weichselian. (6) From the amino‐acid data, it is shown that there has been an episodic style of sedimentation through the Quaternary. (7) of the investigated sediments (which span the last 1 mill. year) ca 98% have been deposited under arctic to boreal‐arctic conditions.

After Sleipner A policy for UK gas supplies

The decision by the UK government to reject the import of Norwegian gas from the Sleipner field, has determined the sources of UK gas supplies up to the early 1990s. Incredibly, the single most important British energy policy decision of the mid-1980s (and perhaps of the entire decade), failed to arouse any significant public interest. Moreover, the excitement which followed the announcement of the intention to privatize the British Gas Corporation (BGC) within the lifetime of the present government, obscured the much more important issue of future UK gas supplies. In spite of its avowed disdain for energy policy making, the government has arrived at a policy for UK gas supplies. This article looks at the reasons behind the Sleipner decision and its consequences for the UK gas market in the 1990s.

Recent developments within the UK energy sector

The Government's decision to veto the British Gas Corporation's proposed contract for the Norwegian Sleipner gas field, the abolition of the British National Oil Corporation, the year-long mining dispute and the proposed privatisation of the gas industry have all been major events in the United Kingdom's energy sector over the past two years (i.e. 1983–1985). The prospects for continued competition between natural gas and coal in the industrial market combined with the electricity supply industry's plans to increase the proportion of nuclear capacity of its system is likely to constrain the prospects for increased coal use in the short and medium terms.