Pressure Support Through Large Scale Gas Cap Water Injection At Prudhoe Bay

2002 ◽  
Author(s):  
Jhaveri Bharat ◽  
Gary Youngren ◽  
Joe Dozzo ◽  
Lynn Schnell ◽  
Matt Maguire
Keyword(s):  
Large Scale ◽  
Pressure Support ◽  
Water Injection ◽  
Prudhoe Bay

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.

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.

Investigating the Mixing Efficiencies of Liquid-to-Liquid Chemical Injection Manifolds for Aquatic Invasive Species Management

2018 ◽  
Vol 141 (3) ◽  
Author(s):  
Thomas J. Zolper ◽  
Aaron R. Cupp ◽  
David L. Smith
Keyword(s):  
Invasive Species ◽  
Large Scale ◽  
Open Systems ◽  
Mixing Time ◽  
Water Injection ◽  
The United States ◽  
Aquatic Invasive Species ◽  
Chemical Treatments ◽  
Invasive Organisms ◽  
Closed Systems

Aquatic invasive species (AIS) have spread throughout the United States via major rivers and tributaries. Locks and dams positioned along affected waterways, specifically lock chambers, are being evaluated as potential management sites to prevent further expansion into new areas. Recent research has shown that infusion of chemicals (e.g., carbon dioxide) into water can block or kill several invasive organisms and could be a viable option at navigational structures such as lock chambers because chemical infusion would not interfere with vessel passage or lock operation. Chemical treatments near lock structures will require large-scale fluid-mechanic systems and significant energy. Mixing must extend to all stagnation regions within a lock structure to prevent the passage of an invasive fish. This work describes the performance of both wall- and floor-based CO2-infused-water to water injection manifolds targeted for lock structures in terms of mixing time, mixing homogeneity, injection efficiency, and operational power requirements. Both systems have strengths and weaknesses so selection recommendations are given for applications such as open systems and closed systems.

The Key Technology Research of the Water Injection System Energy Saving for Super Low Permeability Reservoir in Changqing Oil Field

2012 ◽  
Vol 524-527 ◽  
pp. 1217-1222 ◽  
Author(s):  
Zhi Qiang Huang ◽  
Zhen Chen ◽  
Gang Zheng ◽  
Jian Qiang Xue ◽  
Xue Yuan Li
Keyword(s):  
Energy Consumption ◽  
Energy Saving ◽  
Large Scale ◽  
Water Injection ◽  
High Energy ◽  
Economic Benefits ◽  
Oil Field ◽  
Injection System ◽  
Low Permeability ◽  
Load Rate

With the characteristics of low permeability, pressure and abundance, it's extremely hard to exploit the super low permeability reservoirs in ChangQing oil field. For this reason, the water injection recovery technique has been widely used. Analysis showed that a serious problem of high energy consumption exist in the water injection system, the power consumption of which accounts for about 44%. And the energy cost of pump units reach up to 43%, it's the highest energy consumption link in the system. In this paper the load rate classification method (LRCM) is firstly adopted to statistical analyze water injection stations, which are divided into the owing and over load rate stations. As a result, the owing load rate stations accounts for 83.8%, with a serious phenomenon of the Big Horse Pull A Small Carriage, causing the large-scale backflow in the station, and the efficiency is low, the energy consumption is on the high side. Aimed at water injection stations with different load rate, the methods of reasonable shutting down the pumps, pump replacement, optimizing the transmission ratio and piston size, as well as the speed control technology have been used to make the outlet flow and actual demand reasonable matching. The test result shows that the energy saving technology is well targeted, simple, practical and low cost. The pump units’ efficiency improves obviously, the consumption reduces by 10%, which greatly improve the oilfield economic benefits.

The Forties Field, Block 21/10, 22/6a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 301-308 ◽  
Author(s):  
J. M. Wills
Keyword(s):  
North Sea ◽  
Pressure Support ◽  
Significant Contribution ◽  
Average Rate ◽  
Water Injection ◽  
Submarine Fan ◽  
Artificial Lift ◽  
Stock Tank ◽  
Year 2000 ◽  
Exploration Well

AbstractThe Forties Field is located 180 km (112 miles) ENE of Aberdeen, predominantly in UK Licence Block 21/10. It was discovered in 1970, when an exploration well encountered hydrocarbons in Palaeocene sandstone within an anticlinal structure. Four appraisal wells confirmed the existence of a major oilfield, with an area of approximately 90 sq km (35 sq miles) at a depth of approximately 2000 m (6500 ft). The reservoir occurs in thick Late Palaeocene sandstones deposited in two major sand-rich submarine fan sequences.The field has been producing oil since September 1975. Stock Tank Oil Initially in Place (STOIIP) has been calculated as 4343 MMBBL, and original reserves estimated as 2470 MMBBL, representing an overall recovery of 57%. The field came off plateau production of 500 000 BOPD in 1981, and by mid-1989 production had declined to about 250 000 BOPD. After fourteen years production, the field has produced more than 2 billion STB. Remaining reserves are about 500 MMBBL which includes recovery via artificial lift. Field life has been projected to extend beyond the year 2000.Water injection into the aquifer commenced in 1976, and continues at the present day at an average rate of 390 000 BWPD. There is also a significant contribution to pressure support from the underlying aquifer.At present there are 103 available wells in the field, 81 producers and 22 injectors.

Performing a High Resolution surface Gravity Survey to Monitor the Gas Cap Water Injection Project, Prudhoe Bay, Alaska

2002 ◽  
Author(s):  
Jerry L. Brady ◽  
John F. Ferguson ◽  
Carlos V.L. Aiken ◽  
John E. Seibert ◽  
Tianyou Chen ◽  
...  
Keyword(s):  
High Resolution ◽  
Water Injection ◽  
Surface Gravity ◽  
Gravity Survey ◽  
Prudhoe Bay

An assessment of the Upper Succession and the related secondary reservoirs in the Welton Field, onshore UK

2016 ◽  
Vol 8 (1) ◽  
pp. 595-609 ◽  
Author(s):  
James Steventon ◽  
Mike Bowman
Keyword(s):  
Large Scale ◽  
Water Injection ◽  
Soft Rock ◽  
Oil Field ◽  
Content Type ◽  
Fine Grained ◽  
Delta Plain ◽  
Supplementary Material ◽  
Petrophysical Logs ◽  
Crevasse Splay

AbstractThe Welton oil field has produced nearly 20 MMBO (million barrels of oil) since discovery in 1981. Now in post-plateau decline, there is increasing reliance on a series of secondary reservoirs. Production has been from a suite of stacked reservoirs deposited by large-scale prograding delta-plain systems of early Westphalian age. Whilst the bulk of production has been from the Basal Succession, a considerable upside is considered to exist in the less well-studied Upper Succession that comprises predominantly distributary channel and crevasse splay deposits which have produced in excess of 3 MMBO. These accumulations occur within the Deep Soft Rock, Deep Hard Rock and Tupton reservoirs.This paper focuses on a sedimentological analysis of cored intervals, integrated with petrophysical logs and detailed production data to enable further recommendations to identify areas of undrained pay, along with identifying additional reservoir management activities that could optimize future offtake from the field. These reservoirs consist predominantly of very fine-grained sandstone, with permeability values rarely attaining 100 mD and average porosity values of 10–12%.Recommendations include executing tracer communication tests and building a detailed field model, as well as a pilot water-injection scheme to increase production from some of Welton's secondary reservoirs.Supplementary material: A full set of detailed sedimentological logs for each of the cored wells in this study is available at https://doi.org/10.6084/m9.figshare.c.3593984

The Pierce Field, Blocks 23/22a and 23/27, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 550-559 ◽  
Author(s):  
M. Hale ◽  
R. Laird ◽  
J. Gavnholt ◽  
P. F. van Bergen
Keyword(s):  
Pressure Support ◽  
Water Injection ◽  
East Central ◽  
Field Development ◽  
Gas Compression ◽  
Phases Of Development ◽  
Original Field ◽  
Reservoir Geometry ◽  
The Uk ◽  
Ratio Optimization

AbstractThe Pierce Field lies 250 km east of Aberdeen, in the UK sector of the East Central Graben. The field comprises twin salt diapirs, forming the trap for oil and free gas in the Paleocene–Eocene Forties Sandstone Member reservoir. The diapirs exerted a strong influence over the sedimentation of the reservoir, with the construction of multistorey sandstone bodies forming a complex reservoir geometry further complicated by a hydrodynamic aquifer.The field currently produces to the Haewene Brim floating production storage and offloading (FPSO) installation, and has undergone several phases of development as the understanding has matured. It was initially developed with six subsea horizontal oil producers tied back to the FPSO, with produced gas reinjected through two gas injectors. In 2004–05, water injection was introduced to South Pierce to provide increased pressure support and improve sweep. To maximize recovery, four additional oil producers were drilled between 2010 and 2016, with the final (third) gas injector drilled in 2010. Production is primarily constrained by topsides gas compression capacity leading to gas/oil ratio optimization being the focus of the current field management strategy.The final phase of field development, included in the original field development plan, involves depressurization of the field with the installation of a gas export line.

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