The Huntington Field, Block 22/14a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 479-487 ◽  
Author(s):  
Andrew G. Couch ◽  
Samantha Eatwell ◽  
Olu Daini
Keyword(s):  
North Sea ◽  
Deep Water ◽  
Large Scale ◽  
Pressure Support ◽  
Water Injection ◽  
Oil Field ◽  
Injection Wells ◽  
Production Wells ◽  
Regional Basis ◽  
The Uk

AbstractThe Huntington Oil Field is located in Block 22/14b in the Central Graben of the UK Continental Shelf. The reservoir is the Forties Sandstone Member of the Sele Formation, and oil production is from four production wells supported by two water-injection wells, tied back to the Sevan Voyageur FPSO (floating production storage and offloading unit). Initial estimates of oil-in-place were c. 70 MMbbl and the recovery factor at the end of 2017 after 4.5 years of production was 28%, which reflects the weak aquifer and poor pressure support from water injection. The Huntington reservoir is part of a lobate sheet sand system, where low-concentration turbidite sands and linked debrites are preserved between thin mudstones of regional extent. Within the reservoir, three of the thicker mudstone beds can be correlated biostratigraphically on a regional basis. This stacked lobate part of the system sits above a large-scale deep-water Forties channel that is backfilled by a system of vertically aggrading channel storeys. Despite the relatively high net/gross of the reservoir, the thin but laterally extensive mudstones in the upper (lobate) part of the system are effective aquitards and barriers to pressure support from water.

The Emerald Field, Blocks 2/10a, 2/15a, 3/11b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 111-116 ◽  
Author(s):  
D. M. Stewart ◽  
A. J. G. Faulkner
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Maximum Flow ◽  
Oil Field ◽  
Injection Wells ◽  
Initial Development ◽  
Flexible Risers ◽  
Northern North Sea ◽  
The Uk ◽  
Gas Lift

AbstractThe Emerald Oil Field lies in Blocks 2/10a, 2/15a and 3/1 lb in the UK sector of the northern North Sea. The field is located on the 'Transitional Shelf, an area on the western flank of the Viking Graben, downfaulted from the East Shetland Platform. The first well was drilled on the structure in 1978. Subsequently, a further seven wells have been drilled to delineate the field.The Emerald Field is an elongate dip and fault closed structure subparallel to the local NW-SE regional structural trend. the 'Emerald Sandstone' forms the main reservoir of the field and comprises a homogeneous transgressive unit of Callovian to Bathonian age, undelain by tilted Precambrian and Devonian Basement Horst blocks. Sealing is provided by siltstones and shales of the overlying Healther and Kimmeridge Clay Formations. The reservoir lies at depths between 5150-5600 ft, and wells drilled to date have encountered pay thicknesses of 42-74 ft. Where the sandstone is hydrocarbon bearing, it has a 100% net/ gross ratio. Porosities average 28% and permeabilities lie in the range 0-1 to 1.3 darcies. Wireline and test data indicate that the field contains a continouous oil column of 200 ft. Three distinct structural culminations exist on and adjacent to the field, which give rise to three separate gas caps, centred around wells 2/10a-4, 2/10a-7 and 2/10a-6 The maximum flow rate achieved from the reservoir to date is 6822 BOPD of 24° API oil with a GOR of 300 SCF/STBBL. In-place hydrocarbons are estimated to be 216 MMBBL of oil and 61 BCF of gas, with an estimated 43 MMBBL of oil recoverable by the initial development plan. initial development drilling began in Spring 1989 and the development scheme will use a floating production system. Production to the facility, via flexible risers, is from seven pre-drilled deviated wells with gas lift. An additional four pre-drilled water injection wells will provide reservoir pressure support.

The Maureen Field, Block 16/29a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 347-352 ◽  
Author(s):  
P. L. Cutts
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Upper Jurassic ◽  
Reservoir Properties ◽  
Injection Wells ◽  
The North ◽  
Clay Shales ◽  
Gravity Flows ◽  
Production Wells ◽  
The Uk

AbstractThe Maureen Oilfield is located on a fault-bounded terrace in Block 16/29a of the UK Sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in late 1972 by the 16/29-1 well, and was confirmed by three further appraisal wells. The reservoir consists of submarine fan sandstones of the Palaeocene Maureen Formation, deposited by sediment gravity flows sourced from the East Shetland Platform. The Palaeocene sandstones, ranging from 140 to 400 ft in thickness, have good reservoir properties, with porosities ranging from 18-25% and permeabilities ranging from 30-3000 md. Hydrocarbons are trapped in a simple domal anticline, elongated NW-SE, which was formed at the Palaeocene level by Eocene/Oligocene-aged movement of underlying Permian salt. The reservoir sequence is sealed by Lista Formation claystones. Geochemical analysis suggests Upper Jurassic Kimmeridge Clay shales have been the source of Maureen hydrocarbons. Estimated recoverable reserves are 210 MMBBL. Twelve production wells have been drilled on the Maureen Field. A further seven water injection wells have been drilled to maintain reservoir pressure.

scholarly journals Design method and application of accurate adjustment scheme for water injection wells around adjustment wells

2021 ◽  
Author(s):  
Tongchun Hao ◽  
Liguo Zhong ◽  
Jianbin Liu ◽  
Xiaodong Han ◽  
Tianyin Zhu ◽  
...  
Keyword(s):  
Production Efficiency ◽  
Design Method ◽  
Water Injection ◽  
Oil Field ◽  
Productivity Index ◽  
Injection Wells ◽  
Wellhead Pressure ◽  
Production Wells ◽  
Drilling Operations ◽  
The Impact

AbstractAffected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut-in method is to close all water injection wells around the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method uses water injection index and liquid productivity index as target parameters to analyze the correlation between injection and production wells. Select water injection wells with a high correlation and combine other parameters such as wellhead pressure and pressure recovery speed to design accurate adjustment schemes. Low-correlation wells do not take shut-in measures. This method was applied to 20 infill adjustment wells in the Penglai Oilfield. The correlation between injection and production wells was calculated using the data more than 500 injection wells and production wells. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000 m3. This method achieves accurate adjustment for water injection wells that are high correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.

scholarly journals STATUS OF THE J1 RESERVOIR PRODUCTION OF THE VERKH-TARKA OIL FIELD BY JANUARY 2019

2019 ◽  
Vol 2 (1) ◽  
pp. 109-116
Author(s):  
Dmitry Novikov ◽  
Svetlana Pavlova ◽  
Dmitry Kuznetsov ◽  
Fedor Dultsev ◽  
Anatoly Chernykh ◽  
...  
Keyword(s):  
Water Injection ◽  
Oil Field ◽  
Stage Iii ◽  
Injection Wells ◽  
Current State ◽  
Production Wells ◽  
Average Water ◽  
Field Information ◽  
Hydrodynamic Field ◽  
Water Cut

The results of the analysis of geological field information in order to assess the current state of development of the J11 reservoir of the Verkh-Tarka oil field for of January 2019 are reported. The main object of development is at stage III of the fall in oil production. At present, the total well stock of the J11 reservoir is 175 units, of which 134 are active. The monthly volume of water injection into the FPM system reaches 100 thousand m3, and liquid production is about 170 thousand m3 with an average water-cut of producing wells of 63 %. To date, within the deposit, a complex hydrodynamic field has been formed, in which the depressive zones regularly trace the rows of production wells, and the piezoelectric maximums - injection wells.

Northwest Hutton Field, Block 211/27, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 145-151 ◽  
Keyword(s):  
North Sea ◽  
Middle Jurassic ◽  
Water Injection ◽  
Oil Field ◽  
Injection Wells ◽  
Jacket Platform ◽  
Steel Jacket ◽  
Western Flank ◽  
Average Porosity ◽  
Reservoir Sandstones

AbstractThe Northwest Hutton oil field lies in the East Shetland Basin entirely within UK Block 211/27. It was discovered by the Amoco Group 211/27-3 well in April 1975 and is operated by Amoco (UK) Exploration Company. The structure is a series of tilted fault blocks. The reservoir sandstones are the Brent Group Sandstones of Middle Jurassic age deposited in a progradational deltaic environment. The Brent Group sandstones vary in thickness from 320-500 ft over the field. Average porosity ranges from 20% at the crest of the structure to 13% on the western flank with permeability decreasing from an average of 267 md to 1 md. Recoverable oil is estimated to be 145 MMBBL. A total of 26 producing and 9 water injection wells have been drilled from a single steel jacket platform. Production peaked in May 1983 at 86 680 BOPD.

The Kittiwake Field, Block 21/18, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 339-345 ◽  
Author(s):  
K. W. Glennie ◽  
L. A. Armstrong
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Injection Wells ◽  
Solution Gas

AbstractKittiwake was discovered by well 21/18-2 within a 7th Round block, part of Production Licence P351. Highly undersaturated oil is present in the Fulmar Formation and Skagerrak Formation reservoir sequences; 70 MMBBL of reserves is in Fulmar sandstones whereas oil in the Skagerrak is mostly immovable. The field will be developed from a single 16-slot platform with initially 5 producing and 5 water-injection wells. Solution gas is removed via the Fulmar Field pipeline to St Fergus and, as from September 1990, the oil is loaded onto tankers from a single-buoy mooring.

Optimizing Field Development in South Sultanate of Oman Through Deep Water Disposal Dwd Reclassification

2021 ◽  
Author(s):  
Ali Al Jumah ◽  
Abdulkareem Hindawi ◽  
Fakhriya Shuaibi ◽  
Jasbindra Singh ◽  
Mohamed Siyabi ◽  
...  
Keyword(s):  
Deep Water ◽  
Pressure Support ◽  
Local Community ◽  
Water Injection ◽  
Flood Management ◽  
Water Volume ◽  
Reed Beds ◽  
Field Development ◽  
Palm Trees ◽  
Water Disposal

Abstract The South Oman clusters A and B have reclassified their Deep-Water Disposal wells (DWD) into water injection (WI) wells. This is a novel concept where the excess treated water will be used in the plantation of additional reed beds (Cluster A) and the farming of palm trees (Cluster B), as well as act as pressure support for nearby fields. This will help solve multiple issues at different levels namely helping the business achieve its objective of sustained oil production, helping local communities with employment and helping the organization care for the environment by reducing carbon footprints. This reclassification covers a huge water volume in Field-A and Field-B where 60,000 m3/day and 40,000 m3/day will be injected respectively in the aquifer. The remaining total excess volume of approx. 200,000m3/d will be used for reed beds and Million Date Palm trees Project. The approach followed for the reclassification and routing of water will: Safeguard the field value (oil reserves) by optimum water injectionMaintain the cap-rock integrity by reduced water injection into the aquifer.Reduce GHG intensity by ±50% as a result of (i) reduced power consumption to run the DWD pumps and (ii) the plantation of trees (reed beds and palm trees).Generate ICV (in-country value) opportunities in the area of operations for the local community to use the excess water at surface for various projects.Figure 1DWD Reclassification benefits Multiple teams (subsurface. Surface, operations), interfaces and systems have been associated to reflect the re-classification project. This was done through collaboration of different teams and sections (i.e. EC, EDM, SAP, Nibras, OFM, etc). Water injection targets and several KPIs have been incorporated in various dashboards for monitoring and compliance purposes. Figure 2Teams Integration and interfaces It offers not only a significant boost to the sustainability of the business, but also pursues PDO's Water Management Strategy to reduce Disposal to Zero by no later than the year 2030 This paper will discuss how the project was managed, explain the evaluation done to understand the extent of the pressure support in nearby fields from DWD and the required disposal rate to maintain the desired pressures. Hence, reclassifying that part of deep-water disposal volume to water injection (WI) which requires a totally different water flood management system to be built around it.

Triassic mudstones of the Central North Sea: cross-border characterization, correlation and their palaeoclimatic significance

2020 ◽  
pp. SP494-2019-61
Author(s):  
Stuart G. Archer ◽  
Tom McKie ◽  
Steven D. Andrews ◽  
Anne D. Wilkins ◽  
Matt Hutchison ◽  
...  
Keyword(s):  
North Sea ◽  
Large Scale ◽  
Regional Scale ◽  
Climatic Conditions ◽  
Fluvial Systems ◽  
Correlation Lengths ◽  
Cross Border ◽  
The Uk ◽  
Stratigraphic Nomenclature ◽  
Central North Sea

AbstractThe Triassic of the Central North Sea is a continental succession that contains prolific hydrocarbon-bearing fluvial sandstone reservoirs stratigraphically partitioned by mudstones. Within the Skagerrak Formation of the UK sector, hydrocarbon accumulations in the Judy, Joanne and Josephine Sandstone members are top sealed by the Julius, Jonathan and Joshua Mudstone members, respectively. However, UK and Norwegian stratigraphic correlations have been problematical for decades, largely due to biostratigraphic challenges but also due to the non-uniqueness of the lithotypes and because the cross-border stratigraphic nomenclature differs and has yet to be rationalized. This study focuses on mudstones rather than sandstones to unify cross-border correlation efforts at a regional scale. The mudstone members have been characterized by integrating sedimentological, petrophysical and geophysical data. The facies are indicative of playa lakes that frequently desiccated and preserved minor anhydrite. These conditions alternated with periods of marshy, palustrine conditions favourable for the formation of dolostones. Regional correlations have detected lateral facies changes in the mudstones which are important for their seismically mappable extents, resulting palaeogeographies and, ultimately, their competency as intraformational top seals. Significant diachroneity is associated with the lithological transitions at sandstone–mudstone member boundaries and although lithostratigraphic surfaces can be used as timelines over short distances (e.g. within a field), they should not be assumed to represent timelines over longer correlation lengths. Palaeoclimatic trends are interpreted and compared to those of adjacent regions to test the extent and impact of climate change as a predictive allogenic forcing factor on sedimentation. Mudstone member deposition occurred as a result of the retreat of large-scale terminal fluvial systems during a return to more arid ‘background’ climatic conditions. The cause of the member-scale climatic cyclicity observed within the Skagerrak Formation may be related to volcanic activity in large igneous provinces which triggered the episodic progradation of fluvial systems.

The Machar Field, Block 23/26a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 523-536 ◽  
Author(s):  
Zoë Sayer ◽  
Jonathan Edet ◽  
Rob Gooder ◽  
Alexandra Love
Keyword(s):  
North Sea ◽  
Debris Flows ◽  
Water Injection ◽  
Salt Diapir ◽  
Reservoir Quality ◽  
Complex Interplay ◽  
Light Oil ◽  
High Matrix ◽  
The Uk ◽  
Central North Sea

AbstractMachar is one of several diapir fields located in the Eastern Trough of the UK Central North Sea. It contains light oil in fractured Cretaceous–Danian chalk and Paleocene sandstones draped over and around a tall, steeply-dipping salt diapir that had expressed seafloor relief during chalk deposition. The reservoir geology represents a complex interplay of sedimentology and evolving structure, with slope-related redeposition of both the chalk and sandstone reservoirs affecting distribution and reservoir quality. The best reservoir quality occurs in resedimented chalk (debris flows) and high-density turbidite sandstones. Mapping and characterizing the different facies present has been key to reservoir understanding.The field has been developed by water injection, with conventional sweep in the sandstones and imbibition drive in the chalk. Although the chalk has high matrix microporosity, permeability is typically less than 2 mD, and fractures are essential for achieving high flow rates; test permeabilities can be up to 1500 mD. The next phase of development is blowdown, where water injection is stopped and the field allowed to depressurize. This commenced in February 2018.

scholarly journals Shale volume and permeability of the Miocene unconsolidated turbidite sands of Bonga oil field, Niger delta, Nigeria

2017 ◽  
Vol 5 (1) ◽  
pp. 37 ◽  
Author(s):  
Inyang Namdie ◽  
Idara Akpabio ◽  
Agbasi Okechukwu .E.
Keyword(s):  
Niger Delta ◽  
Gamma Ray ◽  
Water Saturation ◽  
Strong Dependence ◽  
Water Injection ◽  
Oil Field ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Log Data ◽  
Shale Volume

Bonga oil field is located 120km (75mi) southeast of the Niger Delta, Nigeria. It is a subsea type development located about 3500ft water depth and has produced over 330 mmstb of hydrocarbon till date with over 16 oil producing and water injection wells. The producing formation is the Middle to Late Miocene unconsolidated turbidite sandstones with lateral and vertical homogeneities in reservoir properties. This work, analysis the petrophysical properties of the reservoir units for the purpose of modeling the effect of shale content on permeability in the reservoir. Turbidite sandstones are identified by gamma-ray log signatures as intervals with 26-50 API, while sonic, neutron, resistivity, caliper and other log data are applied to estimate volume of shale ranging between 0.972 v/v for shale intervals and 0.0549 v/v for turbidite sands, water saturation of 0.34 v/v average in most sand intervals, porosity range from 0.010 for shale intervals to 0.49 v/v for clean sands and permeability values for the send interval 11.46 to2634mD, for intervals between 7100 to 9100 ft., Data were analyzed using the Interactive Petrophysical software that splits the whole curve into sand and shale zones and estimates among other petrophysical parameters the shale contents of the prospective zones. While Seismic data revealed reservoir thickness ranging from 25ft to over 140ft well log data within the five wells have identified sands of similar thickness and estimated average permeability of700mD. Within the sand units across the five wells, cross plots of estimated porosity, volume of shale and permeability values reveal strong dependence of permeability on shale volume and a general decrease in permeability in intervals with shale volume. It is concluded that sand units with high shale contents that are from0.500 to0.900v/v will not provide good quality reservoir in the field.

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