THE GEOLOGY OF THE HARRIET OILFIELD, OFFSHORE WESTERN AUSTRALIA

1987 ◽  
Vol 27 (1) ◽  
pp. 152
Author(s):  
D.G. Osborne ◽  
E.A. Howell
Keyword(s):  
Residual Oil ◽  
Submarine Fan ◽  
Commercial Development ◽  
Oil Accumulation ◽  
Water Contact ◽  
Seismic Surveys ◽  
Oil Reserves ◽  
Group Hydrocarbon ◽  
Oil Water ◽  
Paraffinic Oil

The Harriet Oilfield, discovered in November 1988, is situated within offshore permit WA-192-P in the Barrow Sub-basin. Following the Harriet 1 discovery well, detailed seismic surveys were recorded and a further ten wells were drilled on the structure between 1988 and 1985. Nine of the wells were completed as producers and one was plugged and abandoned as a dry hole.The oil accumulation occurs in a low relief, fault-dependent closure on the upthrown side of the Lowendal Fault. The trap is mainly structurally controlled but stratigraphic barriers are believed to be locally present, based on differing oil-water contacts in Harriet B-3 and Harriet A-5. These indicate the presence of three hydrocarbon pools separated by permeability barriers.The massive Flag Sandstone reservoir of Lower Cretaceous (Neocomian) age was deposited in a submarine fan environment, northward of the advancing Barrow Group delta. Reservoir quality is very good, with average core porosity of 22 per cent and permeabilities mainly in the range 800-2 000 md. However, a broad oil-water transition zone is developed above the oil-water contact. A residual oil zone is present below the oil-water contact in the northeastern area of the field, suggesting tilting of the structure after initial accumulation of the oil. The gross oil column in the main, Central Pool is 19-21 m with a gas cap up to 10 m thick. The 37° API crude is a relatively unaltered, high quality, paraffinic oil probably sourced from the Jurassic Dingo Claystone.The Harriet Field is the first commercial development of a Barrow Group hydrocarbon accumulation. Recoverable oil reserves are currently estimated at 21 million barrels. The field came on stream in January 1986 and by October 1986 oil production was averaging 10 000 barrels/day.

scholarly journals Optimization of reserve production from water oil zones of D3ps horizon of Shkapovsky oil field by means of horizontal wells

Georesursy ◽  
2019 ◽  
Vol 21 (3) ◽  
pp. 55-61 ◽  
Author(s):  
Rustem F. Yakupov ◽  
Vyacheslav Sh. Mukhametshin ◽  
Ilgizar N. Khakimzyanov ◽  
Viktor E. Trofimov
Keyword(s):  
Oil Field ◽  
Residual Oil ◽  
Hydrodynamic Models ◽  
Water Contact ◽  
Oil Reserves ◽  
Physical Conditions ◽  
Production Values ◽  
Cone Formation ◽  
Oil Water ◽  
Water Cut

An analysis was made of the development of sections of the D3ps formation of the Devonian terrigenous sequence of the Shkapovsky field, with a share of contact zones of more than 78%, which showed that the exploitation of deposits by vertical and deviated wells is unprofitable. Studies show that the development of reserves at the facility occurs along highly permeable interlayers located in the plantar. The construction of sectoral geological and hydrodynamic models showed a detailed distribution of residual oil reserves by area and section in areas with low production values. When analyzing the parameters of the operation of wells with horizontal completion, it was found that the selection of mobile oil reserves localized in a volume limited by the plane of the initial oil-water contact and the surface formed by the rise of the oil-water contact when pulling the water cone to the wells with horizontal completion is comparable with the period of reaching a water cut of 95%. The volumetric method was used to calculate the moving oil reserves in the area of ​​water cone formation. It is recommended to drill wells with horizontal completion as an effective method of additional production of residual oil reserves in fields with similar geological and physical conditions.

USE OF HEAVY MINERAL SUITES IN RESERVOIR SAND STUDIES IN THE HARRIET FIELD, BARROW SUB-BASIN, WESTERN AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 359
Author(s):  
John Scott ◽  
Pete Di Bona ◽  
Vincent Beales
Keyword(s):  
Heavy Mineral ◽  
Time Interval ◽  
Reflection Seismology ◽  
Submarine Fan ◽  
Water Contact ◽  
Wireline Logs ◽  
Total Composition ◽  
Oil Water ◽  
Heavy Mineral Analysis ◽  
Diagenetic History

Analysis of the heavy mineral suites in the reservoir at Harriet Field has significantly improved reservoir unit definition and correlation and provided information on facies changes and diagenetic history. It has provided further evidence for a stratigraphic barrier as a cause of the variation of the oil-water contact in the field.The reservoir consists of a number of discrete sandstone bodies which are arranged in a multistorey manner.The reservoir is further subdivided into compartments by minor faulting. Prior to the use of heavy mineral analysis, correlation between wells was often unclear. Such correlation is beyond the resolution of reflection seismology and the massive nature of the sandstones means that definition and correlation is uncertain when made on the basis of lithology combined with wireline logs. The time interval involved in the deposition of the reservoir sequence is too short to permit discrimination by palaeontological analysis.Eight distinct sandstone bodies can be defined on the basis of analysis of the heavy mineral suites in the 14 wells of the field. The total composition of the suites, certain 'marker minerals' and various statistical indices have been used to define these sandstone units which are interpreted to be individual lobes within a submarine fan complex. The methods and results are illustrated with examples from the field. The results of the analysis show that heavy mineral populations can provide critical information for accurate reservoir mapping and analysis.

Discrimination between pressure and fluid saturation changes from time‐lapse seismic data

Geophysics ◽  
2001 ◽  
Vol 66 (3) ◽  
pp. 836-844 ◽  
Author(s):  
Martin Landrø
Keyword(s):  
Seismic Data ◽  
Time Lapse ◽  
Seismic Survey ◽  
Baseline Survey ◽  
Water Contact ◽  
Data Set ◽  
Seismic Surveys ◽  
Fluid Saturation ◽  
Oil Water ◽  
Pressure Changes

Explicit expressions for computing saturation‐ and pressure‐related changes from time‐lapse seismic data have been derived and tested on a real time‐lapse seismic data set. Necessary input is near‐and far‐offset stacks for the baseline seismic survey and the repeat survey. The method has been tested successfully in a segment where pressure measurements in two wells verify a pore‐pressure increase of 5 to 6 MPa between the baseline survey and the monitor survey. Estimated pressure changes using the proposed relationships fit very well with observations. Between the baseline and monitor seismic surveys, 27% of the estimated recoverable hydrocarbon reserves were produced from this segment. The estimated saturation changes also agree well with observed changes, apart from some areas in the water zone that are mapped as being exposed to saturation changes (which is unlikely). Saturation changes in other segments close to the original oil‐water contact and the top reservoir interface are also estimated and confirmed by observations in various wells.

The Central Brae Field, Blocks 16/07a, 16/07b, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 183-190 ◽  
Author(s):  
Keith J. Fletcher
Keyword(s):  
Upper Jurassic ◽  
Western Boundary ◽  
The South ◽  
Submarine Fan ◽  
Water Contact ◽  
The North ◽  
Oil Water ◽  
Clay Formation ◽  
A Minor ◽  
North And South

abstractThe Central Brae Oilfield is the smallest of three Upper Jurassic fields being developed in UK, Block 16/07a. The field was discovered in 1976 and commended production in September 1989 through a sub-sea template tied back to the Brae 'A' platform in the South Brae Oilfield. The field Stooip is 244 MMBBLs, and by May 1999 cumulative exports of oil and NGL reached 44 MMBBLs.The Central Brae reservoir is a proximal submarine fan sequence, comprising dominantly sand-matrix conglomerate and sanstone with a minor mudstone units. The sediments were shed eastwards off the Fladen Ground Spur and were deposited as a relatively small and steep fan at the margin of the South Viking Graben. Mudstone facies border the submarine fan deposits to the north and south, forming stratigraphic seals. The structure is a faulted anticline developed during the latest Jurassic and early Cretaceous, initially formed as a hangingwall anticline during extension but subsequently tightened during compressional phases. The western boundary of the field is formed by a sealing fault, whilst to the east, there is an oil-water contact at 13426 ft TVDss. The overlying seal is the Kimmeridge Clay Formation, which also interdigitates with the coarser facies basinwards and provides the source of the hydrocarbons.

Polymer Flooding in North Sea Reservoirs

1982 ◽  
Vol 22 (03) ◽  
pp. 353-362 ◽  
Author(s):  
Paul Davison ◽  
Eric Mentzer
Keyword(s):  
Porous Media ◽  
High Temperature ◽  
North Sea ◽  
High Salinity ◽  
Oil Reservoirs ◽  
Water Contact ◽  
Oil Reserves ◽  
The North ◽  
The North Sea ◽  
Oil Water

Abstract The use of polymer solutions to enhance oil-displacement efficiency by seawater injection in North Sea oil reservoirs has been investigated. We have evaluated over 140 polymers for viscosity retention and porous media flow performance under high temperature (90 deg. C), high salinity, and high pressure. Scleroglucan polymers give the best performance in our tests. Polyacrylamides (PAAm's) are particularly unsuitable for mobility control. Using polymers to enhance seawater injection and waterflooding processes is not practical in North Sea reservoirs, but selective injection may improve local sweep efficiencies. Introduction North Sea Waterflooding With 95% of Ne crude oil reserves of Western Europe and 90% of the current crude oil production coming from deposits lying under the North Sea bed, oil producers have been prepared to exploit them by making the high capital investment in the new technology of deepwater production platforms. Seawater injection schemes have been introduced early in the life of many/ North Sea fields, and are featuring in Middle East and North and South American offshore field development programs. Most North Sea oils are fairly light, and many can be produced at high rates from thick oil zones in good permeability sandstone reservoirs. The principal aim of the injection schemes has been to maintain reservoir pressure with peripheral injectors positioned mainly below the oil/water contact. Until now, the main problem has been to keep the seawater injection rates high enough. With the incentive of producing more of the North Sea oil reserves, research is being done to ameliorate some other foreseeable problems. One major problem is the severe channeling of injection water, leading to seawater breakthrough into production wells, and the likelihood of barium sulfate scale formation. Channeling resulting from mobility ration effects may be through high-permeability layers (most North Sea reservoirs are very heterogeneous), fractures, or viscous oils. Another factor reducing efficiency is the general rise of the oil/water contact, causing the producing wells to cut excessive quantities of water. Selectively placed polymer injection treatments may reduce channeling, and polymer squeeze treatments may restrict water production. Polymers and other chemical additives need to have adequate chemical stability in the high-salinity, high-temperature environment of North Sea oil reservoirs. Accurate prediction of reservoir performance of enhanced oil recovery (EOR) techniques requires precise data on the behavior of crude oils and relevant aqueous systems in porous media at reservoir conditions. This paper reports thermal stability and porous media test results for a range of polymer types and discusses their possible use to augment North Sea waterflooding. Experimental Polymers Tested. We screened more than 140 polymers, which we classify as polyacrylamides (PAAm's), polyvinylpyrrolidones (PVP's), hydroxyethylcelluloses (HEC's), cellulose sulfate esters (CSE's), guar gums, xanthans, and scleroglucans. Solution Preparation. Solutions were made up in the manner of Hill et al. in seawater (0.45 um filtered) obtained from Chesil beach on the English southwest coast. The seawater contained residual (less than 0.2 ppm) hypochlorite biocide, from a treatment added on collection. Polymer solutions were characterized by filtration profiles through 5-um Millipore filters (at 0.069-MPa driving pressure, and following prefiltration) and by Brookfield ultralow viscometer measurements at 25 and 55 deg. C, with parameters to represent the solution viscosity at high and low shear rates. SPEJ P. 353^

Possible occurrences of transition zones and residual oil zones below oil-water contacts in mature oil fields, southeast Saskatchewan

2016 ◽  
Vol 4 (4) ◽  
pp. T591-T612 ◽  
Author(s):  
Chengyu Yang ◽  
Hairuo Qing
Keyword(s):  
Williston Basin ◽  
Residual Oil ◽  
Permian Basin ◽  
Water Contact ◽  
Oil Saturation ◽  
Transition Zones ◽  
Recovery Techniques ◽  
Oil Water ◽  
Log Interpretation ◽  
Pool Area

A transition zone (TZ) from oil to water formed by capillary force beneath traditionally defined producing oil-water contact (OWC) has been well-known for years. Recent research and production activities in the Permian Basin and the Williston Basin in United States suggests that a residual oil zone (ROZ) may exist below traditionally defined OWC under certain geologic and hydrodynamic conditions. If this ROZ is sufficiently thick and extensive, it may be economically recoverable using tertiary recovery techniques. We have investigated possible occurrences of TZ/ROZ in the Williston Basin, southeast Saskatchewan, using well-log interpretation based on Archie’s equation. Out of 33 pools examined, we have evaluated three areas, the Bellegarde Tilston pool area, an unnamed Souris Valley pool, and the Rosebank Alida pool area, as possibly having thick (up to 47 m) low-oil-saturation TZ/ROZs below the OWCs. Evidence includes oil stains, core-based oil saturation, fluorescence on drill cuttings, and oil shows and sulfur water reported in drill stem tests. The oil in place within the possible TZ/ROZs is estimated to be approximately half the amount of the oil within their associated main pay zones. Tilted OWC and other findings may suggest that the identified oil-bearing zones are ROZs related to hydrodynamics. The hydrodynamic flows may also have created some other ROZs that still remain undiscovered.

Sign in / Sign up

Export Citation Format

Share Document