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- Volume 8, Issue 4, 2002
Petroleum Geoscience - Volume 8, Issue 4, 2002
Volume 8, Issue 4, 2002
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How can we help ensure success of oil and gas field rehabilitation projects?
Authors Alan P. Heward and Jon G. GluyasOil field redevelopments or rehabilitation projects have become commonplace within the past decade. There are a number of reasons for this, not least that large old fields often contain significant quantities of remaining petroleum. Other major factors are that countries rich in petroleum but hitherto inaccessible to western oil companies have opened up their fields and as the world’s basins become thoroughly explored, field redevelopments look more attractive as the prospects for frontier exploration diminish.
Although now commonplace, field rehabilitations differ widely from redeveloping one’s own field in a familiar basin to entering a new country to work on an aging giant accumulation. The chance of success also varies widely, with modest redevelopments of one’s own fields commonly achieving success but bold forays into new countries and old fields often heralding commercial failure.
There are a number of actions that can be taken to improve the chance of success for any rehabilitation project. The selection of people forming the teams involved in evaluation and implementation requires considerable attention. If overseas, build on the know-how and experience of national staff. Every effort must be made to understand how the field performed and was worked in the past. The old well and production data need to be gathered, sorted, interpreted and made accessible to all in the project. The initial redevelopment targets must be modest, testing of hypotheses rigorous and acquisition of monitoring data on such pilot schemes extensive. ‘New technology’ may help but it is unlikely to be a panacea. Major financial outlay on, for example, new facilities should not be made until an understanding is achieved of how new wells and completions behave during production. Finally, success should be celebrated when success happens rather than celebrating proffered success before the project begins.
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Kadanwari Gas Field, Pakistan: a disappointment turns into an attractive development opportunity
Authors Nasir Ahmad and Siddique ChaudhryKadanwari Gas Field, located in the Middle Indus Basin of Pakistan, was discovered in 1989. Lower Goru sands of Cretaceous age are the producing reservoir in this field. Initially, the structure was considered a relatively simple four-way closure with continuous sand. During appraisal, three wells were drilled and each of these tested gas. On the basis of these results 728×109 SCF of sales gas reserves were estimated and a processing facility was designed accordingly. Due to the corrosive and sour nature of Kadanwari gas, 22% chrome alloy was used in the well completion and surface facilities. Additional development wells and early production data indicated that the reserves were much smaller than originally estimated. After further studies, including reprocessing of seismic data, the reserves were revised downward to less than 200×109 SCF; by that time a total of nine wells had been drilled. Although the field was considered to be a disappointment, the subsurface studies continued and, as a result, the tenth well tested a new fault compartment, proving an accumulation of considerable reserves. As a result of detailed studies of the field, a number of other opportunities were also identified. Presently, the sales gas reserves are estimated at approximately 300×109 SCF and this has given a new life to the field. Some other independent fault-bounded structures in the field are now considered prospective and these have the potential to add sales gas reserves ranging from 100–500 bcf.
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Innovative use of petrophysics in field rehabilitation, with examples from the Heather Field
Authors Simon Kay and Steve CuddyThe Heather oil field is located in the Northern North Sea and is operated by DNO Heather Limited. Oil is produced from sandstones of the Middle Jurassic Brent Group. Although approaching non-commercial flow rates, infill projects are under way which target unswept oil. At this late stage in field life, projects are typified by extracting as much new oil from the field as possible with minimal expenditure. These result in incomplete or degraded log data. This paper describes how the application of innovative techniques can replace data shortfalls, providing quality data without compromising budgetary constraints.
Four infill wells were drilled during 2000 and 2001. Innovative petrophysical techniques have been used to enhance the electric log data gathered. Fuzzy logic techniques have been applied to predict reservoir permeability and choose perforating intervals. Some sections of the highly deviated wells were necessarily logged in sliding mode and fuzzy logic was also used to repair the resulting degraded log curve data. Following the infill well programme, field production has increased from 5000 BBL oil per day (BOPD) to 7000 BOPD. This success was partly due to the better location of wells, particularly 2/5-H62Y, because of the improved reservoir model resulting from these petrophysical techniques.
The height above free-water level (HAFWL) was estimated across the Heather Field using the so-called FOIL function (bulk volume of water plotted as a function of HAFWL) ( Cuddy 1993 ). The FOIL function has given valuable insights into free-water level variation across the Heather Field and has improved water saturation modelling. A method is presented in this paper for geosteering using the FOIL function.
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Redevelopment of the Brighton Marine Field, Trinidad . . . the early days
Authors Roderick J. Wallis, Nazir Ali, Peter Barnes, Franklin Khan and Oliver WhitfieldIn October 1999, the Brighton Marine Block was awarded to Venture Production Company Trinidad Limited and Petrotrin, the Trinidadian National Oil Company, with Venture as operator.
The challenges to improved field recovery posed by such a complex field, with more than 50 years of production history, are many. The field has potential, but requires new interpretations and ideas based on both new and old datasets, a phased programme of rehabilitation and a long-term development plan that will generate immediate value without compromising long-term oil production.
Discovered in 1951, the Brighton Marine Field has produced almost 58×106 STB from an oil in place of over 500×106 STB. Production peaked at 14 000 BOPD in 1967 but had not exceeded 1000 BOPD since 1983.
Some 275, mostly deviated, wells were drilled into the field from 11 onshore pads and 9 offshore platforms. In the year since Venture assumed operations, production rose to nearly 2000 BOPD through field infrastructure rehabilitation, well work-overs and the implementation of new field management processes. In early 2001, the first new well proved the presence of a commercial quantity of petroleum in a hitherto undepleted part of the field.
It is very early in the rehabilitation process and much remains uncertain, but significant progress has been made in understanding the field and tapping its full potential. The field’s first 3D seismic survey, acquired in 1997, has provided a significant enhancement to the understanding of a structurally and stratigraphically complex field. The field compartmentalization and 50 years of production, have complicated the distribution of pressures, sweep and compaction. In order to mitigate risks, a phased strategy was implemented. This process focuses initially on the most straightforward, cost-effective opportunities. These redevelopments are designed to maximize data collection, test new models and help finance more extensive developments. Already, this approach is starting to yield results, although it is still early days.
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Well-bore reservoir evaluation technologies to optimize field revitalization
By I. D. BryantThe economic success of field revitalization projects depends upon draining reservoir compartments that frequently contain smaller reserves volumes than those targeted by the initial field development, in a cost-effective manner. Well-bore measurements can contribute to risk management of redevelopment by identifying and monitoring the drainage of remaining hydrocarbons. Applications of cased-hole and open-hole measurements to optimizing field redevelopment are illustrated using case studies from the Brent Field, UK; Block IV, Venezuela and the T&J Ashworth Lease, USA.
Cased-hole logging using nuclear tools has evolved from time-lapse monitoring to detect changes in saturation to also include through-casing formation evaluation. Where deep invasion prevents the use of these nuclear methods, through-casing resistivity tools can successfully detect hydrocarbons.
Open-hole formation pressures can significantly impact redevelopment strategies, as can evaluation of filtrate invasion using open-hole array resistivity tools. Emerging permanent sensor technologies enable continuous monitoring of both water saturation and formation pressure, thereby offering the potential to improve the performance of future field revitalization projects.
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Balder and Jotun – two sides of the same coin? A comparison of two Tertiary oil fields in the Norwegian North Sea
More LessThe Balder and Jotun fields are located on the western flank of the Utsira High, close to the eastern pinch-out of a Tertiary submarine fan system. Although similar in many aspects, the fields display important depositional, structural and stratigraphic differences which influence the choice of development strategy. The subsurface development strategy for the fields has been designed to optimize oil capture and minimize risk based on the interpreted reservoir geology. Therefore, differences between the exploration histories and reservoir geology are reflected in the development strategy of the two fields.
Both fields comprise Tertiary reservoir sands shed from the East Shetland Platform and transported across the Viking Graben area onto the Utsira High by sandy debris flows and turbidites. These distal gravity flow deposits display both thin-bedded sands and thicker more massive sandstones (>100 m). In the Balder Field, an intricate interaction between deposition and soft sediment deformation processes generated a complex network of reservoir compartments with common fluid contacts. In the Jotun Field, the oil–water contact is also common between all three structures, but a gas cap is restricted to one of the structures.
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Changes in matrix thermal conductivity of clays and claystones as a function of compaction
Authors Douglas W. Waples and Henrik TirsgaardVertical matrix thermal conductivities of clays and claystones in onshore Denmark decrease with decreasing porosity, probably because of increasing orientation of highly anisotropic clay platelets during compaction. The relationship between vertical matrix conductivity λ vm and porosity for this dataset can be expressed as either λ vm=2.544exp(0.943φ) or λ vm=2.749exp (0.637φ), depending upon the statistical methods used to analyse the data. Using the first equation the vertical matrix conductivity of the Danish clays and claystones is found to be about 4.9 W m−1 K−1 in highly porous sediments, decreasing to 2.54 W m−1 K−1 when porosity reaches zero. Using the second equation the vertical matrix conductivity of the Danish clays and claystones is about 4.3 W m−1 K−1 in highly porous sediments, decreasing to about 2.75 W m−1 K−1 at zero porosity. Anisotropy varies from an assumed value of 1.02 in highly porous clays to 2.44 at zero porosity using the first equation, and 1.87 at zero porosity using the second equation. These values agree well with measured data.
This phenomenon is probably common or universal in fine-grained clay-rich sediments, and this method of data analysis could probably be applied to most or all claystone datasets. However, the equations derived in this study will be most appropriate for shales and claystones with comparatively high quartz contents similar to those of the samples analysed. Other specific relationships will probably exist for clay-rich shales and more-pure claystones.
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Microstructural and petrophysical characterization of Muderong Shale: application to top seal risking
Authors David N. Dewhurst, Richard M. Jones and Mark D. RavenAnalysis of the Muderong Shale from the Carnarvon Basin suggests the shale is dominated by interstratified illite–smectite with a high percentage of illite interlayers. Capillary pressure measurements indicate that gas columns of c. 250 m could be sealed by such shale, although the choice of drying method used does influence the accuracy of this calculation. Freeze drying yielded the most consistent threshold pressure results, whereas air drying and vacuum drying showed a greater range of values. Similar calculations in regard to carbon dioxide sequestration indicate column heights of between 550 m and 750 m could be retained. Column height variation is primarily dependent on the contact angle of supercritical carbon dioxide with shale. Microstructurally, the shale is clay supported, exhibiting differential compaction of clays around more rigid grains and containing numerous high aspect ratio discontinuous fractures. These fractures do not affect the capillary properties of the shale, even when injection is fracture-parallel, suggesting they are unlikely to influence reservoir-scale fluid-flow properties. Comparison of the Muderong Shale laboratory data with hydrocarbon column heights from Carnarvon Basin discoveries indicate that top seal failure by capillary breakthrough is unlikely given the maximum lengths of hydrocarbon columns encountered to date. Potential for top seal failure is more likely to be influenced by formation integrity, pore pressure and in situ stress conditions.
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Volumes & issues
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Volume 30 (2024)
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Volume 29 (2023)
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Volume 28 (2022)
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Volume 27 (2021)
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Volume 26 (2020)
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Volume 25 (2019)
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Volume 24 (2018)
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Volume 23 (2017)
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Volume 22 (2016)
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Volume 21 (2015)
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Volume 20 (2014)
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Volume 19 (2013)
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Volume 18 (2012)
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Volume 17 (2011)
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Volume 16 (2010)
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Volume 15 (2009)
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Volume 14 (2008)
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Volume 13 (2007)
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Volume 12 (2006)
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Volume 11 (2005)
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Volume 10 (2004)
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Volume 9 (2003)
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Volume 8 (2002)
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Volume 7 (2001)
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Volume 6 (2000)
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Volume 5 (1999)
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Volume 4 (1998)
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Volume 3 (1997)
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Volume 2 (1996)
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Volume 1 (1995)