An Integrated Petrophysical Workflow for Fluid Characterization and Contacts Identification Using NMR Continuous and Stationary Measurements in a High-Porosity Sandstone Formation, Offshore Norway

2021 ◽  
Vol 62 (2) ◽  
pp. 210-226
Author(s):  
Maciej Kozlowski ◽  
◽  
Diptaroop Chakraborty ◽  
Venkat Jambunathan ◽  
Peyton Lowrey ◽  
...  
Keyword(s):  
Relaxation Time ◽  
Data Quality ◽  
Spin Relaxation ◽  
North Sea ◽  
Column Height ◽  
Reservoir Quality ◽  
Formation Evaluation ◽  
The North ◽  
Nmr Data ◽  
Fluid Properties

The Alvheim Field in the Norwegian North Sea was discovered in 1998. Two wells were drilled in 2018 in the Gekko structure to confirm oil column height and to evaluate reservoir quality in the Heimdal Formation. A comprehensive wireline logging program, including NMR and formation testing, was optimized to reduce formation evaluation uncertainty. Evaluating fluid properties, oil column height, and reservoir quality were primary objectives. Well A was first drilled on the south of the structure, followed by Well B on the north of the structure. Reservoir quality encountered in both wells was very good, and a project to develop these resources is currently in the selection phase. Formation evaluation uncertainty encompassing pore geometry distribution, permeability, reservoir quality, and hydrocarbon identification are mitigated by studying the nuclear magnetic resonance (NMR) log response. NMR fluid typing has been widely used in the oil industry since the 1990s. NMR fluid typing today is a combination of the contrast of spin relaxation time T1, the spin-spin relaxation time T2 (T1T2), and the diffusivity (T2D) of formation fluids (Chen et al., 2016). NMR fluid typing can be obtained from a continuous log and/or stationary log measurements. This paper showcases excellent, textbook-quality NMR data, as well as the integration of NMR data in the petrophysical workflow. High-confidence fluid properties and fluid contacts are determined. This paper also highlights a comparison of NMR data acquired in stationary vs. continuous depth-based log modes in both wells. The continuous log data quality is equivalent to stationary data, implying continuous log data quality is sufficient for reliable NMR fluid properties evaluation without depending on time-consuming stationary NMR measurements. Reducing logging operations rig time is very advantageous in the North Sea, where drilling rig operations cost is high, and enhanced rig time management is constantly required.

Depositional facies, diagenetic clay minerals and reservoir quality of Rotliegend sediments in the Southern Permian Basin (North Sea): a review

Clay Minerals ◽  
1982 ◽  
Vol 17 (1) ◽  
pp. 55-67 ◽  
Author(s):  
U. Seemann
Keyword(s):  
Clay Minerals ◽  
North Sea ◽  
Effective Porosity ◽  
Hydrocarbon Exploration ◽  
Reservoir Quality ◽  
Burial Diagenesis ◽  
Permian Basin ◽  
Northern Margin ◽  
The North

AbstractThe Southern Permian Basin of the North Sea represents an elongate E-W oriented depo-centre along the northern margin of the Variscan Mountains. During Rotliegend times, three roughly parallel facies belts of a Permian desert developed, these following the outline of the Variscan Mountains. These belts were, from south to north, the wadi facies, the dune and interdune facies, and the sabkha and desert lake facies. The bulk of the gas reservoirs of the Rotliegend occur in the aeolian dune sands. Their recognition, and the study of their geometry, is therefore important in hydrocarbon exploration. Equally important is the understanding of diagenesis, particularly of the diageneticaily-formed clay minerals, because they have an important influence on the reservoir quality of these sands. Clay minerals were introduced to the aeolian sands during or shortly after their deposition in the form of air-borne dust, which later formed thin clay films around the grains. During burial diagenesis, these clay films may have acted as crystallization nuclei for new clay minerals or for the transformation of existing ones. Depending on their crystallographic habit, the clay minerals can seriously affect the effective porosity and permeability of the sands.

scholarly journals The Evaluation of Reservoir Quality of Mishrif Formation in South and North Domes of Buzurgan Oil Field

2019 ◽  
Vol 9 (4) ◽  
pp. 89-106
Author(s):  
Ali Duair Jaafar ◽  
Dr. Medhat E. Nasser
Keyword(s):  
Physical Properties ◽  
Water Saturation ◽  
Oil Field ◽  
Reservoir Quality ◽  
Petrophysical Properties ◽  
The South ◽  
Reservoir Properties ◽  
Formation Evaluation ◽  
The North

Buzurgan field in the most cases regards important Iraqi oilfield, and Mishrif Formation is the main producing reservoir in this field, the necessary of so modern geophysical studies is necessity for description and interpret the petrophysical properties in this field. Formation evaluation has been carried out for Mishrif Formation of the Buzurgan oilfield depending on logs data. The available logs data were digitized by using Neuralog software. A computer processed interpretation (CPI) was done for each one of the studied wells from south and north domes using Techlog software V2015.3 in which the porosity, water saturation, and shale content were calculated. And they show that MB21 reservoir unit has the highest thickness, which ranges between (69) m in north dome to (83) m in south dome, and the highest porosity, between (0.06 - 0.16) in the north dome to (0.05 -0.21) in the south dome. The water saturation of this unit ranges between (25% -60%) in MB21 of north dome. It also appeared that the water saturation in the unit MB21 of south dome has the low value, which is between (16% - 25%). From correlation, the thickness of reservoir unit MB21 increases towards the south dome, while the thickness of the uppermost barrier of Mishrif Formation increases towards the north dome. The reservoir unit MB21 was divided into 9 layers due to its large thickness and its important petrophysical characterization. The distribution of petro physical properties (porosity and water saturation) has shown that MB 21 has good reservoir properties.

Submerged Prehistory in the North Sea

2012 ◽  
Author(s):  
Antony Firth
Keyword(s):  
Data Quality ◽  
North Sea ◽  
Direct Relationship ◽  
Archaeological Sites ◽  
Human History ◽  
The North ◽  
Marine Aggregates ◽  
Technological Developments ◽  
The North Sea ◽  
Marine Aggregate

This article looks at the prehistory of the North Sea. The North Sea has a long human history and is geographically extensive. This article gives information about artifacts excavated from coastal exposures, dating back to 700,000 years. It describes the model used to study submerged prehistoric contexts in the North Sea. Marine aggregates play a central role in the investigation of submerged prehistory. The submerged river gravels are considered to be of high potential for prehistoric archaeology, which establishes a direct relationship between submerged prehistory and marine aggregate dredging. This article also explains the theory of Doggerland and its conception. Despite a small number of archaeological sites in the North Sea, recent technological developments have had a big effect with respect to data quality, position-fixing, processing, and presentation.

Permeability prediction from MICP and NMR data using an electrokinetic approach

Geophysics ◽  
2006 ◽  
Vol 71 (4) ◽  
pp. F49-F60 ◽  
Author(s):  
P. W. Glover ◽  
I. I. Zadjali ◽  
K. A. Frew
Keyword(s):  
Grain Size ◽  
North Sea ◽  
Glass Bead ◽  
Geometric Mean ◽  
New Model ◽  
The North ◽  
A Value ◽  
Nmr Data ◽  
Mean Grain Size ◽  
The North Sea

The accurate modeling of oil, gas, and water reservoirs depends fundamentally upon access to reliable rock permeabilities that cannot be obtained directly from downhole logs. Instead, a range of empirical models are usually employed. We propose a new model that has been derived analytically from electrokinetic theory and is equally valid for all lithologies. The predictions of the new model and four other common models (Kozeny-Carman, Berg, Swanson, and van Baaren) have been compared using measurements carried out on fused and unfused glass bead packs as well as on 91 rock samples representing 11 lithologies and three coring directions. The new model provides the best predictions for the glass bead packs as well for all the lithologies. The crux of the new model is to have a good knowledge of the relevant mean grain diameter, for example, from MICP data. Hence, we have also predicted the permeabilities of 21 North Sea well cores using all five models and five different measures of relevant grain size. These data show that the best predictions are provided by the use of the new model with the geometric mean grain size. We have also applied the new model to the prediction of permeability from NMR data of a [Formula: see text] thick sand-shale succession in the North Sea by inverting the [Formula: see text] spectrum to provide a value for the geometric mean grain size. The new model shows a good match to all 348 core measurements from the succession, performing better than the SDR, Timur-Coates, HSCM, and Kozeny-Carman predictions.

Automated Drilling-Fluids-Measurement Technique Improves Fluid Control, Quality

2021 ◽  
Vol 73 (11) ◽  
pp. 53-54
Author(s):  
Chris Carpenter
Keyword(s):  
Ambient Temperature ◽  
North Sea ◽  
Drilling Fluid ◽  
Pressure Sensors ◽  
Drilling Fluids ◽  
Sampling Point ◽  
Electrical Stability ◽  
The North ◽  
Fluid Properties ◽  
The North Sea

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204041, “Automatic Drilling-Fluids Monitoring,” by Knut Taugbøl, SPE, Equinor, and Bengt Sola and Matthew Forshaw, SPE, Baker Hughes, et al., prepared for the 2021 SPE/IADC International Drilling Conference and Exhibition, originally scheduled to be held in Stavanger, 9–11 March. The paper has not been peer reviewed. The complete paper presents new units for automatic drilling-fluids measurements with emphasis on offshore drilling applications. The surveillance of fluid properties and the use of data in an onshore operations center is discussed. The authors present experiences from use of these data in enabling real-time hydraulic measurements and models for automatic drilling control and explain how these advances can improve safety in drilling operations and drilling efficiency. Introduction An operator has worked with different suppliers for several years to find and develop technology for automatic measurements of drilling-fluid properties. In the described study, methods for measuring parameters such as viscosity, fluid loss control, pH, electrical stability, particle-size distribution, and cuttings morphology and mineralogy were all fitted into a flow loop in an onshore test center. These tests, however, were all performed with prototype equipment. Since then, work has continued to optimize equipment for offshore installations, made for operating in harsh environments and requiring limited maintenance to provide continuous and reliable data quality. The fluid-measuring technique presented in this paper is based on rheology measurement through a pipe rheometer and density measurements through a Coriolis meter. This rheometer measures at ambient temperature. Dual DP is the terminology that refers to pressure measurements between two differential pressure sensors. The dual-DP pipe rheometer is set up with high-accuracy pressure transducers to measure pressure loss inside the straight section of the pipe rheometer. By varying the flow rate through pipes of different dimensions, a rheology profile at varying shear rates can be calculated. Field Implementation Installation of a unit begins with a rig survey conducted in concert with the drilling contractor to find the best location and sampling point. Fluid normally is taken from the charge manifold for the mud pumps, ensuring measurement of the fluid going into the well. The first installation in the North Sea of an automatic fluid-monitoring (AFM) unit was in 2017. This unit is still operational, sending data to an onshore support center. Fig. 1 shows such a unit installed offshore. The AFM unit has only one movable part, the monopump supplying drilling fluid through the unit. Once the dual-DP rheometer was factory-acceptance-tested in the yard, it was sent offshore to be commissioned and verified on a fixed installation in the North Sea. The related data presented in the complete paper were acquired in the field while drilling the 355-m, 8½-in. section with 1.35-SG low-equivalent-circulating-density oil-based drilling fluid, with drilling conducted at approximately 4000 m measured depth. The mud engineer onboard was requested to perform rheology checks on a viscometer at equal ambient temperature to the AFM so that the results could be compared; the AFM also measures rheology at ambient temperature.

The Clyde Field, Block 30/17b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 279-285
Author(s):  
D. A. Stevens ◽  
R. J. Wallis
Keyword(s):  
Production Rate ◽  
North Sea ◽  
Late Jurassic ◽  
Water Injection ◽  
Reservoir Quality ◽  
Reservoir Pressure ◽  
Shallow Marine ◽  
The North ◽  
Fault Block ◽  
The North Sea

AbstractThe Clyde Field, which was discovered in 1978, is located on the SW edge of the North Sea Central Graben. The reservoir is developed with Late Jurassic shallow marine sands of the Fulmar Sand Formation. An estimated 408 MMBBL of oil is present (Annex B), of which 154 MMBBL is considered recoverable.The structure of the Clyde Field takes the form of a rotated Jurassic fault block, truncated at its crest by a major unconformity. Oil is retained within a combination trap, sourced from Late Jurassic Kimmeridge Clay thermally matured in the highly productive basinal lows, adjacent to the field.Reservoir sand quality is highly variable, ranging from excellent with permeabilities in excess of Id, to poor with permeabilities of less than 1 md. The principal control on reservoir quality appears to be original depositional texture, although strong diagenetic effects are also present.Production is from a single, centrally located, platform provided with thirty slots. Aquifer support is insufficient to maintain reservoir pressure at the current plateau production rate of 50 000 BOPD and so a programme of water injection has been implemented.

scholarly journals Chalk Reservoirs of the North Sea

1982 ◽  
Vol 30 ◽  
pp. 119-137
Author(s):  
R. F. P. Hardman
Keyword(s):  
North Sea ◽  
Pore Space ◽  
Source Rocks ◽  
Reservoir Quality ◽  
Pressure Solution ◽  
Burial Depth ◽  
High Porosity ◽  
The North ◽  
Sea Bed ◽  
The North Sea

In the North Sea, chalk became a reservoir for oil and gas by a combination of fortunate circumstances. Shortly after burial chalk in general has a high porosity, but a low permeability. It is a micropore reservoir. For fluids to enter the pore space, pressure is necessary. North Sea Chalk hydrocarbon fields are all located over thick areas of Kimmeridge and Oxford Clay source rocks on structures which grew during the Tertiary. Structural growth caused fracturing allowing hydrocarbons, which were generated from as early as Oligocene times onwards, to build up in the fracture systems within structural closures in the Chalk. In this way hydrocarbons were able, by their buoyancy or by the pressure generated from the shales below, to enter chalk reservoirs. In areas where Paleocene sands are present, a closed pressure system was not present and no saturation of the Chalk was possible. Chalk is composed of the debris of coccolithophorids, which being composed of low magnesian calcite is of great chemical stability. Although early diagenetic effects such as compaction by dewatering and loss of aragonite are recognised, burial diagenesis does not start until approximately 1000 m below surface. In the case of North Sea Chalk reservoirs, diagenesis, which will normally reduce porosity from approximately 50% at the sea bed to 10% at between 3000 and 4000 m burial depth, is arrested by three factors; the pressure generated, as mentioned above, which partially or wholly supports the overburden, thus reducing or preventing pressure solution; oil or gas in the pore space, which, as a chemically inert fluid also largely prevents pressure solution; magnesium ions, present in sea water and in greater concentrations in the pore-waters of up-domed beds overlying Zechstein evaporites, which poison sites of nucleation of calcite retarding diagenesis. As a result all Chalk fields show anomalously high values of porosity. Valhall Field for instance has values of 50% porosity at a depth of 2500m. Chalk reservoir quality is controlled by a variety of factors, but four factors predominate; the purity in terms of calcium carbonate of the sediment; the rate of deposition of the Chalk which in tum determines the degree of early frame-work cement; the tectonic setting of the field area during Chalk deposition; and the size distribution of the coccoliths being deposited. To these four factors nearly all reservoir quality variation can be related. The best Chalk reservoir in the North Sea is undoubtedly the Tor Formation because of its purity, but the Lower Hod Formation and, in places where allochtonous sheets of Tor Formation have slid in during its deposition, the Ekofisk Forma­tion, can act as very satisfactory North Sea Chalk reservoirs.

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