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M. Grist, M. Simpson, R. Milton-Worssell, Oil & Gas Directorate, DTI
Introduction
The Central and Northern North Sea has followed a typical exploitation path for a hydrocarbon producing area with large conventional fields being developed first and thereafter smaller fields utilising the infrastructure. Now we have entered a third phase with the development of technically more difficult fields such as heavy oil fields (eg. Captain), and High Pressure High Temperature (HPHT) fields. Exploration has followed the same trend although influenced by serendipity and in recent years rapidly advancing technology. The path or trend is due to the obvious economic drivers which select the highest value lowest risk targets currently available. There are other relevant factors such as safety (well control, material limits), drilling technology available and environmental policies (gas acceptability as fuel).
The DTI here defines HPHT fields as being those with reservoir pressure exceeding 10,000 psi (690 bar) and reservoir temperature above 300 deg. F ( 149 deg C) (1) They can arise simply by extreme depth as in Italy's Po Valley (2) and in far northern Siberia and we should expect a range of such fields in very deep sedimentary basins but none seem deep enough in the North Sea. Fields that reach HPHT conditions due to abnormal pressure gradients can exist widely but clearly have had to survive tectonic stresses that could rupture their multiway seals. In either case we should expect HPHT fields to be confined to specific locations and in the North Sea two such areas are the Central Graben and the Viking Graben (fig 1). Reservoirs with abnormal pressure gradients cannot be expected to be super major fields because seals are not likely to be maintained over very large areas. High gas content fluids are to be expected due to the partial cracking of large molecules at past high temperatures (3). Countering the size/seal constraint is the fact that at elevated pressure the gas-in-place is enhanced and the high temperature will ensure low fluid viscosity to offset lower permeabilities. Furthermore the producing drive energy in a reservoir will be considerable.
History
The classic HPHT field is Thomasville(4), onshore in the USA where much early technical development took place in the seventies and economic development was proved. From the late eighties large fields in the Norphlet trend in the Gulf of Mexico (5) showed the way for offshore development of deep sour reservoirs. In the UK, HPHT fields were not looked for at first and then avoided from the mid eighties when it was difficult to drill and test them let alone produce . The discouragement of the Ocean Odyssey incident on well 22/30b-3 in 1988 (6) persisted for some time and may be one reason why Norwegian HPHT fields were developed first. 15,000 psi BOP stacks and hoses become more available from the end of the 1980's permitting safer drilling. Early discoveries were Rhum (1977),Puffin (1981) and Franklin(1986). Elsewhere in Europe[in Italy's Po Valley and in the Vienna Basin (6) ] and in the USA, onshore HPHT fields were being developed and the engineering technology for their development was demonstrated. As noted above Norwegian offshore fields Embla (1993) and Lille Frigg (1994) came forward further advancing and demonstrating development possibilities offshore.
UK Pioneers
Interestingly in the UKCS, it was Marathon that showed the way both for large stand alone gas condensate field operation at North Brae (start up 1988) and for deep hot fields with the underlying Beinn field. Beinn started in 1992 although it is not quite in the HPHT category. Ranger demonstrated the use of a 20,000psi BOP stack on well 29/4b-3. The first UK producing HPHT field (1997) was Texaco's Erskine gas condensate field in block 23/26 which opened up the deep Central Graben area and showed the use of a not normally manned (NNM) platform and an insulated full fluids line. A little later came the first UK subsea fields Mallard, Heron and Egret which were developed by Shell and addressed the problems of hot well heads and flowlines in a subsea environment.
The technical development effort was matched by the effort of convincing the co-licensees to sanction considerable upfront cost.
Technology Development
Collaborative technology development was encouraged from the beginning by DTI, not only to share costs but also because it was realised that the service industry faced a limited market for component items (1). It is difficult to dissipate equipment development costs over a small number of sales. One well known result has been the widely used HPHT choke but welding methods have also been important. DTI are also pleased to note the informal sharing of experience in drilling and well engineering and the recent extension to long hot subsea flow lines.
Multiphase meters have become available at the right time. They have a much wider application but are particularly suited to measuring HPHT well flows on NNM platforms. Optical sensors and fibre optic data transmission offer hope for improved well monitoring.
Some thirty HPHT development wells have now been drilled in UK fields and some of these have produced at high rates for up to three years. Subsea pipelines handling high temperature product fluids have not been without problems as the limits of conventional subsea pipeline technology have been stretched. Experience has been built up and features understood which has lead to:
New design criteria for insulated pipeline (pipe in pipe).
Pipeline fabrication and installation methods developed which allow the transfer of loads from the external pipe to the inner pipe.
Better understanding of criticality of quality control in installation.
Regular operational surveillance and integrity monitoring.
Technology continues to be developed onshore with the demonstration of high angle drilling in AGIP's Villafortuna field in Italy (2) but this has not yet been implemented offshore.
Whilst we acknowledge the well completion difficulties and the learning experience with hot insulated subsea pipelines, we appear to be approaching a point at which there are solutions or incipient solutions for the development of a range of sizes of offshore fields and hydrocarbon types. Hence new development or exploration prospect value can be assessed. Meantime exploration has delivered a few further UKCS discoveries(Table 1). It is therefore a good time to check the inventory and assess the opportunity in relation to remaining UKCS non HPHT reserves.
Fields on Production
By mid May 2001 six UKCS fields are on production as shown in table 2. Three of these fields are high GOR oilfields, the others gas condensate fields. All lie in the Central Graben area except Mallard which is on the west Central Shelf. The oil fields are all subsea installations with whole well fluid flowlines to nearby infrastructure. Heron and Egret fields share a common production pipeline to the ETAPs centre and have subsea cooling coils to permit pipeline operations within a normal operational PT envelope. Mallard has a 16 km pipeline to Kittiwake platform designed on the above basis of shared stresses. It also has water injection for pressure maintenance. The oilfields have been in operation for 2.5 years with no subsea equipment or well problems attributable to the HPHT character of their fluids. Lille-Frigg in Norway is also a subsea development.
With the gas condensate fields the approach is to place their wells heads and chokes on a separate small platform connected to processing equipment elsewhere. Erskine's processing is carried out on Lomond, 30 km distant. Erskine has been in production since 1997 but with a major interruption due to production pipeline failure. This pipeline was replaced in 2000 using a similar design to that operated for Mallard. Shearwater and Elgin both have wellhead platforms bridge linked to respective processing platforms. These large fields have effectively just started up after coping with commissioning problems. Ahead lie the problems of well productivity maintenance after large scale pressure reduction exceeding 8,000 psi and eventual two phase flow around the well when the dewpoint is passed.
The fields in production demonstrate the successful exploitation of reservoirs in Jurassic horizons (Erskine, Shearwater, Elgin, Mallard) and Triassic (Heron, Egret). There is a mixture of large independent operations and small fields producing to infrastructure.
Fields under Construction
These are two gas condensate fields in the Central Graben and both are to be operated as satellites to adjacent processing centres. They are scheduled to start up by autumn 2001. Both Franklin and Jade have small well head platforms and insulated pipelines conveying the full well streams. Franklin will produce from two Jurassic horizons and Jade from the Triassic. Franklin will supplant Elgin which currently has the deepest production from the North Sea at 5335m, 17,500 ft TVDSS thus extending the opportunity envelope still further .
Fields likely to be developed
Five additional field are named and located on the map (fig 2 ). These are well known as HPHT fields and demonstrate the extent of potential HPHT production . One (Kessog) is currently (May 2001) on the PILOT Accelerator list for participative contractor development.
A few of these fields lie outside the Central Graben area and if brought to production, will indicate how such fields can be integrated into northern infrastructure. All these are in Jurassic formations as is Lille Frigg in Norway block 10/1.
Other discoveries
Ten prospective fields have been discovered, mostly in the Central Graben area in Jurassic formations. All are gas condensates. A further HPHT discovery has been made in the South Viking Graben - again a gas condensate. The Petroleum Act 1998 does not permit DTI to disclose details of the discoveries [without the agreement of the operator ] except in aggregated form as they appear in table 1 and their temperatures and pressures in fig 3.
Their estimated oil and gas reserves appear in the 'possible' totals for the UK in the Brown Book.
The Opportunity
The pie charts on fig 4 show that HPHT fields already provide a substantial proportion of the UK remaining proven and probable (P50) plus potential additional reserves - especially of liquids in the Central North Sea. This proportion is likely to increase as additional HPHT fields are developed and conventional fields run down.
UK gas production is widely predicted to fall below demand in 2004-2005. Pipeline ullage will then be offered widely and will no longer be a hurdle in development. There is no sharp cut off and the expectation is that conveyance of gas to shore will progressively get easier helped by changes in Codes. UK developed gas will compete with gas brought great distances into the country with inevitable transport penalties.
The ETAPs project showed that a number of fields each with a different fluid and production profile, could be developed successfully as a cluster with integrated fluid processing and export.
Some of the as yet undeveloped HPHT fields could benefit from such an approach. A recent DTI study has confirmed that a cluster of 4-6 small gas condensate fields , including HPHT fields could be developed economically on a phase in basis to a new central facility (8 ). Some of the discoveries may however be more conveniently tied back to nearby host platforms. Both the cluster approach and individual field tie-backs rely on the application of subsea technology but this has already been demonstrated in some measure at Heron and Mallard. It is appreciated that subsea well completion and welhead engineering requires further special attention to widen the range and nature of the reservoir fluids that can be handled in this way.
Deep horizons below existing production are another target with some examples already known. Here the extreme temperature is the main obstacle to routing to existing processing systems. One solution is to dilute the hot fluids by co-mingling with those from a shallower formation as already practised with Mallard and Kittiwake fluids. Another solution may be to use an upper reservoir to cool down the fluids ( in reservoir co-mingling) and DTI has commissioned a study to investigate this possibility - with the understanding that well bore access to shut off crossflow would have to be maintained.
Further Exploration Potential
The recent drilling in the HPHT areas has provided some encouraging results from an exploration stand point. We now know from well tests that porosity and permeability can be preserved at great depth (18,000+ ft TVDSS) thus opening the opportunity to explore for prospects below the conventional depth window in the Central Graben area. Development wells have encountered sealing faults again indicating that in these HPHT environments such seals work and down faulted plays are possible. Advances in seismic acquisition especially long offset 2D & 3D are imaging much deeper reflectors and giving confidence to the mapping of as yet undrilled prospects. Steep faults previously difficult to image and sub-salt imaging are now possible in the area. (Fig 5 - description in Appendix). Advances in seismic processing are leading to the ability to predict pressures from seismic data which should mitigate some of the drilling risks.
Our map (fig 1) indicates what is believed to be the principal prospective area for HPHT fields - both new fields and deeper reservoirs adjacent to existing fields. This is extended westwards in comparison to earlier versions as more recent discoveries have indicated trends. Development and discoveries are concentrated in part of the Central Graben yet the existence of outlier discovery wells indicates a wider Jurassic prospectivity. There is also further potential in the Triassic although reservoir quality will be paramount.
A scatter of other discoveries up into the south of the Viking Graben shows that conditions for HPHT reservoirs/fluids and seal maintenance exist more widely. There could be more clusters of such fields awaiting drilling. The thick sediments along the south Viking Graben are inviting.
Exploration for further HPHT reservoirs will depend on recognising the potential for persisting top, bottom and side seals in structural, sedimentary or fault controlled prospects and advanced geophysical acquisition and interpretation methods to raise the success rate. The high cost of an HPHT well is a hurdle to be overcome without ever compromising on integrity and safety and the reputation of the industry as a whole. An important feature of further discoveries is that they will help drive the development of offshore well and production technology .
Overall the known discoveries and step out success so far point to a hydrocarbon resource of some size close to existing infrastructure which will offer increasingly attractive terms for treating and conveyance.
Hot Spot
We see the HPHT area defined on Fig 1 as a hot spot for opportunity on the UKCS. 'Hot' because of the growing ability to exploit discovery, as well as topicality . 'Spot' because the area and horizon is constrained. Ironically it is the temperature of the reservoir and its fluids that is the largest physical hurdle in exploitation !
References
- Overview of the HPHT Fields on the UKCS, Offshore Engineer, 1997
- Five years experience in using downhole pressure gauges in the hostile deep wells of Villafortuna-Trecate Field SPE 2648
- R.C.Leonard ' Distribution of sub-surface pressure in the Norwegian Central Graben and applications for exploration' in Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference, Geological Society London 1993
- Thomasville Field
Corrosion control - deep sour gas production SPE 8310
'Shell makes deep gas pay' Oil & Gas Journal 9 April 1979
- Completion design for deep sour Norphlet gas wells offshore Mobile Alabama 1990 SPE 24772
- Determination in fatal accident inquiry .....Ocean Odessy, Aberdeen:Sherrif Court 1991.
- Drilling the Zisterdorf UT 2A - the deepest in Austria... Erdoel-Erdgas, 101Jg., Hft 4, April 1985
- 'Concept for Gas Condensate Fields' Review report for DTI, available on application to authors.
Appendix
Legend for Figure 5
6km offset 2D Seismic Data Acquired Q4 2000,
Section SW - NE across Central Graben
The 2D seismic line shows a series of tilted fault blocks at Rotliegend level and imaging clarity is sufficient to allow subdivision of the pre-salt stratigraphy. The Zechstein salt has withdrawn almost completely from above the Rotliegend blocks into a large salt diapir, the flanks of which are visible on the left hand edge of the image. Salt withdrawl was accompanied by progressive rotation of the Triassic through to Upper Jurassic section. The contra-rotation of the Rotliegend and Triassic sections were coeval events, decoupled by the mobile salt, placing most of the fault displacement visible in the image at Late Triassic through to Late Jurassic. The Cretaceous onlaps the truncated Triassic through Late Jurassic unconformity surface and the faulted strata are draped and buried by the Chalk. Directly above the Chalk, mounding formed by Upper Palaeocene basin floor sands is clearly imaged beneath a thick, fractured and de-watered Eocene section.
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