Petroleum Geoscience - Volume 3, Issue 1, 1997

The field reserves evaluation strategy developed in this paper is a tool to help recognize and quantify the key uncertainties in field reserve estimates before committing to development. Reserve estimate changes through time for UKCS fields developed over the last 20 years are examined. We examine the causes of these changes and propose a scheme to assess fields in terms of structural complexity and reservoir quality and architecture using nine categories. Applying this scheme, termed "Geoscore", to 33 UKCS fields we show that reserve estimates: (a) for low complexity (low Geoscore) fields are underestimated by an average of 20%; (b) for medium complexity fields are overestimated by 10%; (c) for high complexity (high Geoscore) fields are overestimated by 15%. There is also a trend of decreasing recovery factor with increasing Geoscore. Accurate reserve estimation during field appraisal requires: recognizing the key uncertainties; quantifying the relative importance of these uncertainties; either collecting data or preparing contingency plans to handle potential problems that may arise during field development. We describe the key uncertainties, types of data to be collected and how to handle the remaining uncertainties. Careful application of the Geoscore analysis helps the recognition and quantification of these key uncertainties.

Seismic attribute maps provide a useful tool in interpreting faults, particularly those close to or below seismic resolution. Dip, relief, azimuth and amplitude maps are most useful. Optimal use of such maps requires careful filtering and appropriate use of colours and light sources. One of the challenges is to distinguish between anomalies related to real geological features and to seismic noise--both of which may occur as linear or curvi-linear, continuous features on the attribute maps. This challenge must be solved by use of independent data. In the North Sea Gullfaks Field, a family of (curvi-)linear features on the attribute maps are subparallel to contour lines on time maps. Core data, dipmeter data, stratigraphic log correlation and forward modelling show that these features are related to seismic noise rather than real faults.

Riphean-Vendian strata represent the lowest stratigraphic interval of the East European Platform which could contain undiscovered hydrocarbons. Regional geophysical surveys in the 1990s have aimed at studying the structural features and petroleum potential of the ancient strata of the Moscow syneclise. In the central parts of the platform, Riphean deposits fill deep and extensive graben systems superposed by basins containing thick Vendian sequences. Middle Riphean and Upper Vendian clay-siltstone strata of coastal-marine origin are rich in organic matter of sapropelic type and are source rocks. The geological and geochemical environment is favorable for the formation of oil and gas pools. The main exploration aim is to detect zones with all the criteria favourable for the presence of hydrocarbons, modern geophysical and geochemical exploratory methods playing a crucial role.

The hydrodynamic system within the Chalk of the Greater Ekofisk area and its effect upon pore pressure distribution and hydrocarbon trapping has been analysed. The Chalk of the area is a relatively closed system for fluid movement and has large pressure cells characterized by their own pressure regime, fluid type and trapping potential. The aquifer is near static and there is no significant regional hydrodynamic flow. Overpressure is higher at Valhall than at Eldfisk, Ekofisk or Albuskjell, but Valhall is structurally shallower than Albuskjell. This trend corresponds to a maturity trend for the reservoir fluids, and is related to burial depth, temperature and hydrocarbon charging. As total pore pressure at the top of the structures reaches fracture pressure, leakage occurs. The gas cloud observed on seismic data above Valhall may be due to present-day leakage, whilst the gas clouds above other fields could be related to leakage which occurred when the fracture pressure was lower than today. Overpressuring is a dynamic process dependent on burial, hydrocarbon generation and migration, diagenesis and seal integrity and it controls both chalk porosity and hydrocarbon trapping.

An inclined appraisal well, 30/16-13, drilled in 1992-3 in the north of the Auk Rotliegend oil field, Central North Sea confirmed sufficient gross rock volume to justify a horizontal appraisal/development sidetrack 30/16-13S1 to assess the viability of a horizontal well development for Auk North. Close proximity of the two wells provided an opportunity for an integrated reservoir description. Core over the entire 125 m reservoir section of 30/16-13 was orientated, and tied to dipmeter data, later reprocessed into image logs. These data, plus conventional log responses, enabled a threefold subdivision of the aeolian facies including dune slipface sandstones. The sidetrack was horizontally geosteered through 625 m of reservoir, maintaining a stand-off above the field-wide free water level, and beneath the dipping Top Rotliegend structure unconformity. Careful selection of the optimal azimuth for the horizontal well track to pass up stratigraphic section maximized the number of slipface intervals encountered and preferential permeability pathways to the wellbore. Formation MicroImager (FMI) logs in the horizontal well, calibrated with core and logs from the inclined hole, enabled the characterization of the lithofacies, faults and fractures, including orientations. This detailed reservoir characterization was much greater than could be expected from either hole.

Existing methods and a newly proposed method are used to estimate the magnitudes of the horizontal principal stresses from stress-induced borehole breakouts and leak-off tests. Under the condition that the depth interval between leak-off and breakout is sufficiently small, so that the stress ratios sigma H /sigma v and sigma h /sigma v can be reasonably regarded as constants within the depth range, both horizontal principal stresses sigma H and sigma h can be resolved with some knowledge of breakout width. A comparison of the methods has been conducted with well data from the North West Shelf of Australia. The estimated stress magnitudes are generally consistent with the measured trend from neighbouring modified leak-off (or hydraulic fracturing) tests, and also indicate that the tectonic stress regime in the depth range from 2.6 to 2.9 km, at the location of the borehole, is likely to be on the boundary between extension and strike-slip. Knowledge of the in situ stress field provides a crucial development factor in petroleum engineering, such as the optimum design of inclined or horizontal drilling for maximizing wellbore mechanical stability and recovery from fractured reservoirs.

Productive reefs in the former USSR are known from the Lower Cambrian to the Upper Jurassic. They contain more than 31% of the oil and about 29% of the gas resources of the FSU occurring in carbonate reservoirs. Giant and supergiant fields such as Karachaganak, Tengiz, Zhanazhol, Shurtan etc. are associated with reefs. Reservoir architecture and variation of reservoir properties depends upon the shape and origin of the reefs. Zones of improved reservoir properties are located in the central parts of dome-like reefs or in circumferential or ring-shaped zones in the atoll-like reefs. In asymmetric reef systems the best reservoir intervals are shifted towards the bioherm zone and forereef slope.

Many small gas fields have been discovered in the west of North Shongliao Basin of China while drilling for oil. Applications and results of DTIT and GEOPET II codes indicate that the formation and distribution of these gas fields are controlled by hydrocarbon expulsion and migration from the major Qingshahou source rock. This generated most of the oil and gas at 88-50 Ma and 50-0 Ma, respectively; the ratio of oil to gas is about 70:30. Most of the separate-phase oil was expelled at 35-15 Ma, but no separate-phase gas was expelled because of total solution of generated gas in oil and in connate water. Gas dissolved in water tended to migrate from the deep source rock centre to the West Slope (shallower formations) of the basin through sandstone reservoirs and normal faults, gradually being released from solution and accumulated in traps along the migration route. Gas dissolved in oil tended to migrate to traps around the source rock centre, and was released and accumulated at the tops of oil reservoirs. The best area for prospecting for gas is between 500 m to 2000 m.