Member Reservoir Research Articles

Study on characteristics of tight oil reservoir in Ansai Area of Ordos Basin– take the Chang 6 section of Ordos Basin as an example

ABSTRACT In order to understand the exploration and development potential of tight oil in the oil field exploration and development stage, the reservoir characteristics of Chang 6 oil formation in Ansai area of Ordos Basin were studied. In this paper, the reservoir characteristics are studied by using aseries of experimental data, such as cast sheet, cathodoluminescence, electron probe, conventional mercury injection, constant rate mercury injection experiment, scanning electron microscope, etc. The results show that the lithologic characteristics of Chang 6 reservoir group in Ansai area are mainly feldspathic sandstone, accounting for 64.57%, followed by lithic feldspathic sandstone accounting for 31.36%, the sum of the two accounting for 95.93%. Pores are most developed in Ansai area, and the interstitial materials are mainly chlorite, kaolinite and illite. Primary intergranular pores are mainly developed in this area. Besides primary intergranular pores, there are also some feldspar dissolved pores in Ansai region. There are many laumontite dissolved pores in this region. The reservoir type in Ansai region is “low porosity and ultra low permeability”, but the Chang 6 member reservoir in Ansai region is very well characterized by “low porosity and ultra low permeability”.

Genesis of reservoir heterogeneity and its impacts on petroleum exploitation in beach-bar sandstone reservoirs: A case study from the Bohai Bay Basin, China

Reservoir characteristics of beach-bar sandstone reservoirs in the 2nd member of the Shahejie Formation in Banqiao Sag are studied by means of well logging interpretation, thin section observation and physical property analysis. Further, the influence of deposition, diagenesis and internal architecture interface on reservoir quality are quantitatively analyzed. On this basis, the geneses of reservoir heterogeneity of beach-bar sandstone reservoirs are summarized. The following results are obtained. (1) Primary pores, secondary pores and micro-fractures are the main types of reservoir space in the study area, and the primary intergranular pore is the main pore type; the microscopic heterogeneity of reservoirs is strong, and the physical properties of beach-bar reservoirs in different regions vary widely. (2) Tectonic-deposition, diagenesis and reservoir internal architecture work in unison to cause the heterogeneity of beach-bar reservoir quality in the 2nd member of the Shahejie Formation in Banqiao Sag; the locations and scales of beach-bar sand bodies are obviously different in different fault blocks in the study area, determining the macroscopic distribution of beach-bar reservoirs; differential diagenesis intensifies the degree of reservoir heterogeneity; the fine-grained argillaceous deposits between different architecture units of beach-bar reservoirs are critical to the quality of reservoirs. (3) The differential distribution of beach-bar reservoir quality parameters in the study area affects the spatial heterogeneity of reservoirs, which not only controls the original oil/gas distribution, but also has a significant influence on the effect of waterflooding and leads to the local enrichment of remaining oil.

Prediction of sweet spots in tight sandstone reservoirs based on anisotropic frequency-dependent AVO inversion

Abstract The frequency-dependent amplitude-versus-offset (FAVO) method has become a practical method for fluid detection in sand reservoirs. At present, most FAVO inversions are based on the assumption that reservoirs are isotropy, but the application effect is not satisfactory for fractured reservoirs. Hence, we analyse the frequency variation characteristics of anisotropy parameters in tight sandstone reservoirs based on a new petrophysical model, and propose a stepwise anisotropic FAVO inversion method to extract frequency-dependent attributes from prestack seismic field data. First, we combine the improved Brie's law with the fine-fracture model to analyse frequency-dependent characteristics of velocities and Thomsen anisotropy parameters at different gas saturations and fracture densities. Then, we derive an anisotropic FAVO inversion algorithm based on Rüger's approximation formula and propose a stepwise anisotropic FAVO inversion method to obtain the dispersions of anisotropy parameters. Finally, we propose a method that combines the inversion spectral decomposition with the stepwise anisotropy FAVO inversion and apply it to tight sand reservoirs in the Xinchang area. We use P-wave velocity dispersion and anisotropy parameter ε dispersion to optimise favourable areas. Numerical analysis results show that velocity dispersion of the P-wave is sensitive to fracture density, which can be used for fracture prediction in fractured reservoirs. In contrast, anisotropic parameter dispersion is sensitive to gas saturation and can be used for fluid detection. The seismic data inversion results show that velocity dispersion of the P-wave and anisotropic parameter dispersion are sensitive to fractured reservoirs in the second member of Xujiahe Group, which is consistent with logging interpretation results.

3D geocellular modeling for reservoir characterization of lacustrine turbidite reservoirs: Submember 3 of the third member of the Eocene Shahejie Formation, Dongying depression, Eastern China

3D geocellular modeling is increasingly essential in the petroleum industry; it brings together all petroleum disciplines, and it is commonly used in simulation and production forecast. However, modeling slope and deep-water turbidite reservoirs using conventional modeling methods pose a significant challenge due to the structural complexity and thin-beds associated with these reservoirs. Through the innovative modeling technology of PaleoScan, the reservoirs in Sub member 3 of the third member of the Shahejie Formation are modeled to understand the structural framework. The resulting model is populated with petrophysical properties i.e., porosity and permeability to predict their lateral and vertical distribution within these sandstone reservoirs. The study suggests that the reservoir in the highstand system tract (HST) is characterized by the clinoforms configuration framework. The reservoir is highly faulted mainly in the northern and southeastern parts of the depression. The sedimentary layers are deposited across the slope and downlapping, thinning, and terminating toward to the west. The two isochore surface maps reveal sediment thickness variation and depositional trends within each individual depositional layer. The zones or areas that corresponds to low values on the thickness maps suggest minor uplifts associated with intensive faulting in the Eocene period. These topographical highs played a fundamental role in distributing the sediments delivered to the basin from distant sources. The maps reveal that sediments that filled the basin appear to come from different source points, primarily delivered from the north, southeast, and northeast of the basin with varying depositional trends. The modeled porosity and permeability indicate that the delta fed turbidite reservoirs are characterized by medium to high porosity values of 10–20% and low to medium permeability values of 30-410mD, respectively. The porosity values increase to the southeast and toward the basinwards (west) while permeability varies within the individual sedimentary layers. The distribution of porosity and permeability is not uniform vertically. This suggests the presence of mixed none-reservoir layers with locally and periodically deposited sandstone reservoirs within the stratigraphic during rapid delta progradation. The HST is characterized by six different delta progradation cycles; each phase produced locally deposited lacustrine turbidite sandstones in the basin, which are essential reservoirs in this Formation. The innovative PaleoScan interpretation technology has successfully created a high-resolution 3D reservoir model of this complex geology-such innovative technology is vital to similar complex geology globally.

Differential oil accumulation and its controlling factors for CFD6-4 oilfield at the steep slope belt on the southern margin of Shijiutuo Uplift in Bohai Sea

Biomarkers and stable carbon isotopes suggest that oils accumulated in CFD6-4 oilfield are mixed type by oils derived from source rocks of the third (Es3) and first (Es1) members of Shahejie formation, except the ones from the reservoirs in the third member (Ed3) of Dongying formation of Well A5, which are Es3-derived. Fluid inclusion and basin modeling analyses elaborate two charging periods in CFD6-4 oilfield. The first period initiates at about 7.5 Ma driven by hydrocarbon generating and expelling of source rocks, and another one occurred at about 5.0–2.0 Ma caused by the Neo-tectonic activity in Bohai Sea. The Paleogene fan deltas and their direct contact with source rocks define oil horizontal accumulations in CFD6-4 Oilfield. Due to the poor continuities of fan deltas, oils mainly accumulate near source, leading to oils rich in the east with poor in the west. And oil vertical accumulations in CFD6-4 oilfield depend on fault activity during Neo-tectonic activity in Bohai Sea and sandstone carrier bed of the Guantao (Ng) formation. Oil accumulations in the Paleogene and Neogene strata lies on the activity rate of fault connecting the Paleogene oil favorably accumulating reservoir and the Ng sandstone carrier, because it moved at 5 and 25 m/Ma during Neo-tectonic activity and could be both barrier to and avenue of oils. Furthermore, the oil accumulations in the Neogene strata are restrained by the structural features of the Ng sandstone carrier. Therefore, in order to improve the exploration success rate at the steep slope zones in Bohai Sea, the distribution of fan deltas in the Paleogene strata, thveir contact situations with oil source rocks, and the activity rate of connecting faults during the Neo-tectonic activity should be taken into account.

A quantitative study of the scale and distribution of tight gas reservoirs in the Sulige gas field, Ordos Basin, northwest China

Gas and water distribution is discontinuous in tight gas reservoirs, and a quantitative understanding of the factors controlling the scale and distribution of effective reservoirs is important for natural gas exploration. We used geological and geophysical explanation results, dynamic and static well test data, interference well test and static pressure test to calculate the distribution and characteristics of tight gas reservoirs in the H8 Member of the Shihezi Formation, Sulige gas field, Ordos Basin, northwest China. Our evaluation system examines the scale, physical properties, gas-bearing properties, and other reservoir features, and results in classification of effective reservoirs into types I, II, and III that differ greatly in size, porosity, permeability, and saturation. The average thickness, length, and width of type I effective reservoirs are 2.89, 808, and 598 m, respectively, and the porosity is > 10.0%, permeability is > 10 × 10−3 µm2, and average gas saturation is > 60%. Compared with conventional gas reservoirs, tight gas effective reservoirs are small-scale and have low gas saturation. Our results show that the scale of the sedimentary system controls the size of the dominant microfacies in which tight gas effective reservoirs form. The presence of different types of interbeds hinders the connectivity of effective sand body reservoirs. The gas source conditions and pore characteristics of the reservoirs control sand body gas filling and reservoir formation. The physical properties and structural nature of the reservoirs control gas-water separation and the gas contents of effective reservoirs. The results are beneficial for the understanding of gas reservoir distribution in the whole Ordos Basin and other similar basins worldwide.

Natural gas geology and exploration direction of the Cambrian Lower Canglangpu Member in central Sichuan paleo-uplift, Sichuan Basin, SW China

Based on drilling data of JT1 and CS1, outcrop profiles and seismic data, the sedimentary pattern, space configuration of source-reservoir-cap combinations and paleouplift evolution characteristics of the Cambrian Lower Canglangpu Member in the central Sichuan paleouplift have been investigated to determine the favorable exploration zones. Controlled by Deyang-Anyue rift, the Lower Canglangpu Member features differential characteristics from east to west in sedimentary framework. In the west side of the Deyang-Anyue rift, this member is composed of clastic sediments, while in the east side of the Deyang-Anyue rift, it is fresh water shelf sediments, with grain beaches occurring along edges of the depressions, shelf and lagoon. Among the beaches, the dolomitic ones are mainly distributed around the depression edge and in the north of the lagoon. The beach sediments could become high quality reservoirs under the effect of karstification. Underlying the Lower Canglangpu Member is the widespread source rock of the Qiongzhusi Formation, so oil and gas generated by the Qiongzhusi Formation source rock can directly charge into the beach reservoirs. The sandy mudstone of the Upper Canglangpu Member can serve as the caprock of the Lower Canglangpu Member reservoir. The dolomitic beaches are located at the higher part of the paleo-uplift during the main accumulation period, with good hydrocarbon accumulation elements. Blocks PT1-CS1, HT1-GT2 and east GT2 are favorable exploration zones.

A Provenance Study of Upper Jurassic Hydrocarbon Source Rocks of the Flemish Pass Basin and Central Ridge, Offshore Newfoundland, Canada

A number of hydrocarbon discoveries have been made recently in the Flemish Pass Basin and Central Ridge, offshore Newfoundland, Canada, but there is only limited geological information available. The primary goal of this study was to determine the sedimentary provenance and paleodrainage patterns of mudstones and sandstones from the Upper Jurassic Rankin Formation, including the Upper and Lower Kimmeridgian Source Rock (organic-rich shale) members and Upper and Lower Tempest Sandstone Member reservoirs, in this area. A combination of heavy mineral analysis, whole-rock geochemistry and detrital zircon U-Pb geochronology was determined from cores and cuttings from four offshore wells in an attempt to decipher provenance. Detrital heavy minerals in 20 cuttings samples from the studied geologic units are dominated by either rutile + zircon + apatite ± chromite or rutile + apatite + tourmaline, with minor zircon, indicating diverse source lithologies. Whole rock Zr-Th-Sc trends suggest significant zircon recycling in both mudstones and sandstones. Detrital zircon U-Pb ages were determined in two mudstone and four sandstone samples from the four wells. Five major U-Pb age groups of grains were found: A Late Jurassic group that represents an unknown source of syn-sedimentary magmatism, a Permian–Carboniferous age group which is interpreted to be derived from Iberia, a Cambrian–Devonian group derived from the Central Mobile Belt of the Newfoundland–Ireland conjugate margin, and two older age groups (late Neoproterozoic and >1 Ga) linked to Avalonia. The Iberian detritus is abundant in the Central Ridge and southern Flemish Pass region and units containing sizable populations of these grains are interpreted to be derived from the east whereas units lacking this population are interpreted to be sourced from the northeast and possibly also the west. The Upper Tempest Sandstone contains Mesozoic zircons, which constrain the depositional age of this unit to be no older than Late Tithonian.

Characteristics and main controlling factors of reservoirs in the fourth member of Sinian Dengying Formation in Yuanba and its peripheral area, northeastern Sichuan Basin, SW China

Abstract Based on the abundant outcrops and 3D seismic data in Yuanba and its surrounding areas in northeastern Sichuan Basin, the characteristics, main controlling factors and development regularities of reservoirs in the fourth member of Sinian Dengying Formation (shortened as Deng 4 Member) were analyzed comprehensively. The results show that the reservoirs were mainly developed in microbial dolomite associated with the microbial mound and dolarenite associated with grain beach, and had intergranular dissolution pores, inter-frame dissolution pores and karst caves as main storage space. The reservoirs were large in scale and strong in heterogeneity. The analysis of the reservoir genetic mechanisms shows that the reservoirs in the fourth member of Dengying Formation were the products of karstification on mound-beach facies deposited in the second episode of Tongwan movement. The karstification had the marks of eogenetic karstification such as granophyric karst system and half-dissociation zone. The reservoirs were controlled by the sedimentary facies belt, the mound beach facies was the decisive factor in reservoir development. Further analysis indicates that the Yuanba area had a geological background of well-developed platform margin mound beach facies, so mound beach bodies can be taken as a favorable exploration target.

Microscopic and Fractal Characterization of Organic Matter within Lacustrine Shale Reservoirs in the First Member of Cretaceous Qingshankou Formation, Songliao Basin, Northeast China

Understanding the occurrences of different fractions of organic matter in shale reservoirs is very important for the evaluation of shale oil. Lacustrine organic-rich shale samples from the first member of the Cretaceous Qingshankou Formation in the Songliao Basin were analyzed with confocal laser scanning microscopy (CLSM) and fluorescence spectral analysis. The results show that the occurrences of different organic components are related to the fabric of samples and vary with depth. The bulk content of light components is significantly higher than heavy components and exhibits a positive relationship with quartz and feldspar contents. Both light and heavy components are distributed parallel with the lamination in microscopic view in laminated samples, and randomly in massive samples. The maximum radius of light components in most of the samples is larger than 20 µm, while it is smaller for heavy components, indicating the micro fractionation from clay/organic lamina to quartz/feldspar lamina. The depth of enrichment of light components corresponds to the oil maturity of organic matter. Both the distribution of light and heavy components fits the same fractal model, with fractal dimensions ranging between 2.2 and 2.5. The CLSM results confirm that it can be a reliable tool for the “sweet spot” exploration.

Quantitative evaluation methods of tight reservoirs based on multi-feature fusion: A case study of the fourth member of Shahejie Formation in Liaohe Depression

The formation and development of tight oil reservoirs in the fourth member of the Shahejie Formation (Es4) in the Leijia region of the western sag of the Liaohe Depression are highly heterogeneous and influenced by several factors. The relationship between these variables is extremely complex. In order to avoid deviations caused by single factors and logging data for less drilling when regional tight oil reservoirs have been assessed, quantitative evaluation methods for tight reservoirs based on multi-feature fusion have been proposed. Hand-drawn maps of brittleness index, carbonate rocks thickness, fracture density, mean permeability, and mean porosity are gridded by the Kriging model accompanied by k-means clustering to determine the types of reservoir and classification interval. After that, two quantitative evaluation methods, the overlapping favourability method (OFM) and the principal component analysis (PCA), were used to analyze the five influence factors of the tight oil reservoirs. Finally, reservoir evaluation maps were generated by dividing the interval values into classes. Results show that the weights of the five variables calculated by the hybrid weight method (HWM) are 0.1100,0.4929, 0.0803, 0.2889, and 0.0279. The reservoirs in the study area are finally divided into four types, with the best reservoir types primarily distributed in well areas, such as A99, A82, A91, A78, and A9. At the same time, the main controlling factors for the creation of the reservoir have been analyzed; however, the thickness of carbonate rock in the study area plays a decisive role in the development of high-quality reservoirs. The brittleness index and fracture density can significantly improve the efficiency of the reservoir. Quantitative approaches can effectively and scientifically evaluate the tight reservoirs, which can be widely used.

Pore structure and fluid saturation of near-oil source low-permeability turbidite sandstone of the Dongying Sag in the Bohai Bay Basin, east China

Pore structure and oil saturation are important parameters in petroleum exploration and development, and the relationship between them is closer in near-oil source reservoirs (with a short-distance migration of oil and gas) than in other reservoirs. Using epoxy-impregnated thin sections, scanning electron microscopy (SEM), conventional core analyses of porosity and permeability, mercury intrusion porosimetry, and well logging, the characteristics of the petrology, physical properties, and pore structure we studied, as well as the relationship between pore structure and fluid saturation (maximum mercury intrusion saturation Smax and oil saturation So) of the near-oil source low-permeability turbidite sandstone reservoirs in the Es3 member of the Dongying Sag, Bohai Bay Basin, eastern China. The results indicate that the turbidite sandstone reservoirs are mainly composed of fine sandstone and siltstone, with porosities and permeabilities ranging from 5 to 25% and 0.1 to 40 mD, respectively, and can be classified as medium to low porosity and extra-low to ultra-low permeability reservoirs. The pore types of high-quality reservoirs are mainly dominated by intergranular pores, both primary and dissolved, probably due to the influence of the acidic fluids generated from the cracking of organic matter. The pore structure is complex with respect to the pore-throat size distribution, and the overall pore-throat radius is small. Several pore structure parameters together affect the fluid saturation distribution, among which the medium pore-throat radius (R50) and medium saturation pressure (P50) are especially correlated with oil saturation. Different pore structure types have different characteristics of fluid saturation distribution, and the oil-bearing grade and oil saturation of the reservoirs above the oil-water contact are typically positively correlated with pore structure. This study will help to classify the pore structure in the wellbore profile and improve the accuracy of the oil saturation calculation by well logging.

Petrophysical analysis of Upper Qishn Clastic Member Reservoir, Tawila Oilfield, Yemen

A comprehensive petrophysical study of the Upper Qishn Clastic Member reservoir was conducted at Tawila oilfield in Yemen. An integrated well-logging dataset was analyzed to detect the reservoir properties and hydrocarbon potential. Lithologic data, shale/matrix models, elastic, seismo-facies, and fluid analytical analyses and crossplots were generated to characterize the reservoir. The clastic reservoir was subdivided into four petrophysical zones (S1A, S1B, S2, and S3) having different reservoir properties and hydrocarbon content. Crossplots of dia-porosity, apparent-matrix density, and elastic rock properties revealed a reservoir with mixed rock types primarily composed of quartz, calcite, and feldspars, with rare kaolinite and heavy minerals. A laminated-shale model was found to apply to the S2 and S3 reservoir zones, while dispersed- and structural-shale models best describe the S1A and S1B zones. Pickett and Buckles saturation crossplots indicated that the reservoir is not at irreducible water saturation. The Qishn reservoir exhibits regular and uniform facies of similar thickness throughout the study area with a slight dip toward the northwestern part of the oilfield. Estimated petrophysical parameters for the reservoir are represented by vertical petrophysical analogs and property distribution maps. The vertical petrophysical analogs show that the S2 and S3 zones attained clearly defined reservoir properties compared to S1A and S1B zones. The S2 zone has an effective porosity of 11–19%, permeability of 2–670 mD, and hydrocarbon saturation < 57%. The S3 zone offers an effective porosity of 12–21%, permeability of 4–2000 mD, and hydrocarbon saturation < 61%. Both S1A and S1B zones show weak petrophysical parameters and low hydrocarbon content. Hydrocarbon-distribution maps reveal significant hydrocarbon saturation north of the main east–west-trending fault reaching a maximum associated with low shale volume and excellent effective porosity and permeability values. It was concluded that the S2 and S3 zones are the most hydrocarbon-rich zones in the reservoir and should be further studied and mapped across the study area and the nearby oilfields.

Characteristics and pore evolution of the tight sandstone reservoirs of the Chang-7 Member of the Yanchang Formation in the Xin’anbian area, Ordos basin

More than 100 million tons of tight oil reserves have been discovered in the Xin’anbian area of the Ordos basin in recent years, of which the main reservoir is the Chang-7 Member of the Yanchang Formation. To identify the characteristics of the tight sandstone reservoir and their the development of the Chang-7 Member in the study area, casting thin sections, scanning electron microscopy (SEM), high-pressure mercury injection, cathodoluminescence and other technical methods were used to analyze the reservoir rock types and their physical properties and pore structure. Based on reservoir diagenesis research and quantitative evaluations of reservoir pores, a reservoir pore evolution mode was established. The results showed that the main rock types in the tight sandstone reservoirs in the Chang-7 Member of the Xin’anbian area were lithic feldspathic sandstone and feldspathic detritus sandstone and that the reservoir space types were mainly feldspar dissolved pores, with a few residual intergranular pores, clay intercrystalline pores, and microfractures. The reservoirs were classified as having low porosity and low permeability and extra-low porosity and extra-low permeability. The porosity and permeability of the reservoirs were between 4 ~ 10% and 0.01 ~ 1 mD, respectively, and were mainly controlled by compaction, cementation, and dissolution. Compaction and cementation reduced the porosity and permeability, while dissolution increased the porosity and permeability. The Chang-7 Member reservoir mainly experienced weak-medium compaction, medium-strong cementation, and different degrees of dissolution. The average loss of porosity due to cementation was around 25%, while the average loss due to compaction was around 13%. This research determined four key stages in the porosity evolution of the Chang-7 Member in the study area: (1) the porosity was reduced to 26% from the Triassic to the Early Jurassic period, which was mainly due to compression compaction; (2) the reservoir was seriously damaged by cementation from the Middle Jurassic to Late Jurassic period, where the porosity decreased to 5%; (3) in the Early Cretaceous period, the porosity increased to 11% due to dissolution; and (4) the porosity was reduced to 7% from the late Early Cretaceous to early Late Cretaceous period, which was mainly due to cementation.

Analysis of lithofacies and evaluation of effective reservoirs of member 2 of Xujiahe Formation in the Xinchang area in Western Sichuan

In the Xinchang area in western Sichuan Basin, a total of 121.12 billion cubic meters of proved reserves of natural gas are discovered in Member 2 of Xujiahe Formation, but only 7.739 billion cubic meters of proved reserves of natural gas are produced. The main reason is that sandstones in Member 2 of Xujiahe Formation in the Xinchang area are generally tight, with strong heterogeneity, only intervals with relatively good physical properties have a certain production capacity; therefore, it is very necessary and important to evaluate effective reservoirs in Member 2 of Xujiahe Formation. Through analysis of cores, with consideration of color, sedimentary texture and grain size, lithofacies of Member 2 of Xujiahe Formation in the Xinchang area can be divided into 12 types. According to data of physical properties and thin section analysis, it can be concluded that the favorable lithofacies in the upper submember of Member 2 of Xujiahe Formation are the massive medium-coarse sandstone, the medium-coarse sandstone with cross bedding, and the medium-coarse sandstone with carbonaceous fragments. On the basis of electrical characteristics, well-logging interpretation standards for favorable lithofacies are established, in addition, favorable lithofacies and effective reservoir in the Xinchang area are determined, and distribution of favorable lithofacies (effective reservoir) is identified, which lay a solid foundation for next deployment of appraisal well and development of effective reserves.

川中龙岗地区沙溪庙组沙一段优质储层特征及主控因素研究

川中龙岗地区沙溪庙组沙一段优质储层特征及主控因素研究

The Penguins Cluster, Blocks 211/13a and 211/14, UK North Sea

Abstract The Penguins Cluster of fields are owned jointly (50:50) by Shell UK Ltd (Shell) and Esso Exploration and Production UK Ltd (Esso), with Shell as the operator. The cluster was discovered in 1974 and is composed of a combination of oil and gas condensate accumulations located 50–65 km north of the Brent Field, at the northern end of the North Viking Graben. Two main producing reservoirs are present: the Penguins West Field (Penguin A) consists of an Upper Jurassic Magnus Sandstone Member reservoir, while the Penguins East Field (Penguin C, D and E) consists of a Middle Jurassic Brent Group reservoir, underlain by currently undeveloped Statfjord and Triassic (Cormorant) reservoirs. The Magnus reservoir is composed of turbidite sands with an average porosity of 15% and permeabilities of 0.10–300 mD. The Brent reservoirs are composed of deltaic shoreface deposits with an average porosity of 14% and permeabilities of 0.01–1000 mD. The fields were brought on stream in 2003 as a subsea development via what at the time was the world's longest comingled tieback to the Brent Charlie facility. A total of nine producing wells have been drilled from four subsea manifolds, producing c. 78 MMboe to date through depletion drive.

The Rosebank Field, Blocks 213/27a, 213/26b, 205/1a and 205/2a, UK Atlantic Margin

Abstract The Rosebank Field is located primarily in Block 213/27a in the Faroe–Shetland Basin, c. 130 km west of the Shetland Islands in water depths of c. 1100 m (3600 ft). Hydrocarbons are trapped within an elongate, SW–NE-trending four-way anticlinal structure. The principal Colsay Sandstone Member reservoir consists of several vertically stacked, Late Paleocene to Early Eocene fluvial and deltaic reservoirs separated by volcanic sequences. Well log and core data indicate that reservoir quality is high, with porosities in the range of 19–23% and average permeability of c. 3 D. Oil quality is also high, with average oil gravity of 37°API and in-situ viscosity of c. 1 cP at a mean reservoir temperature of 175°F. The field holds a substantial resource and is currently under evaluation for development.

The Starling, Scoter and Merganser fields, Blocks 22/30a and 29/3a, UK North Sea

Abstract The Shearwater Field is located 242 km east of Aberdeen in the Central North Sea (CNS) and has three satellite fields, Starling, Scoter and Merganser. Acting as the hub for the gas-condensate-producing normal-pressure–normal-temperature (NPNT) satellites, Shearwater, which produces high-pressure–high-temperature (HPHT) Jurassic reservoirs, comprises a bridge-linked wellhead jacket to a production platform. The satellites, developed as subsea tiebacks, target Paleocene turbidite reservoirs, with the Starling Field most distant at 33 km from the host while Merganser is tied in via Scoter through a 15 km pipeline. Each satellite consists of a subsea manifold connected to two production wells at Merganser, and three production wells each at Scoter and Starling. All reservoir traps at the satellites are due to Permian-age Zechstein salt diapirs. Starling and Scoter produce Forties Sandstone Member reservoirs via three deviated wells targeting anticline structures. At Merganser, two long horizontal production wells cross over 4000 ft of faulted Paleocene reservoir intervals to produce under salt diapir overhangs. The satellites have been instrumental in maintaining the Shearwater facilities given early main field well failures, whilst recent challenges have developed as the satellites mature, requiring infill wells and well interventions to maximize economic recovery.

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&amp;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.