Petroleum Geoscience - Volume 5, Issue 2, 1999

Field observations in western Sinai show that damage zones around faults are characterized by (a) a decrease in the frequency of small-scale structures with increasing distance from the master fault, (b) clustering of these structures across damage zones, and (c) a positive relationship between damage zone width and master fault throw in logarithmic space, up to maximum width of about 80 m. This relationship allows damage zone width to be estimated from fault throw, a parameter obtainable from seismic data. Preliminary data on the interconnectivity of structures within damage zones indicate that granulation seams are more likely to intersect than tip out. The thicknesses of small-scale structures were measured, and the cumulative thicknesses of all small-scale structures within individual damage zones calculated. In the examples given, these cumulative thicknesses are up to 1 m within 10-30 m wide damage zones, implying that as much as 1 m of deformed rock, most likely with reduced porosity and permeability, occurs across damage zones. This, together with the interconnectivity data, suggests that the impact of faults on fluid flow may occur not only at fault planes, but throughout their damage zones.

The giant oil field Matzen, located in the Vienna Basin, Austria is subject to a modern geological and geophysical re-examination. Almost 50 years of production make this field a mature asset in traditional terms. 3D seismic and applied sequence stratigraphy are being used to re-assess the geological architecture and the depositional setting of the field. An integrated project approach (quick review-early results, Integrated Petroleum Engineering Studies and a Field Development Plan) is taken to identify and quantify the remaining oil and gas reserves and to assess the most economic and cost-effective production of these reserves. First results reveal a more complex geology than previously recognized--both structurally and stratigraphically--which, in combination with existing production data, will lead to new exploitation opportunities. The future implementation phase--drilling, re-completions, etc--will be based on the findings of the ongoing project.

The Milne Point Unit, North Slope Alaska, contains 2X10 9 BBL STOOIP, in the Late Cretaceous Schrader Bluff Formation. This resource is part of a larger viscous oil accumulation in excess of 26X10 9 BBL STOOIP. Exploitation of the Schrader Bluff commenced in 1991 with an initial 22 well development. Resulting capital and operating costs gave the basis for the larger planned development. These cost projections, coupled with low flow rates--350 BBL oil per day (BOPD)--rendered the project uneconomic and drilling ceased in 1992. BP Exploration (Alaska) Inc. (BPXA) acquired Milne Point in 1994 and laid plans to develop the Schrader Bluff and two deeper reservoirs. Most of the current production comes from two deeper reservoirs, however, work on the problematic Schrader Bluff has continued. Learning through innovative drilling and completion programmes, plus additional technological and contractual innovations, are considered the keys to unlocking the value of this vast viscous oil resource.

Recovery factors for comparable reservoirs are often from 10 to 20% higher in the USA than elsewhere. The reason is the relatively low cost of drilling and work-over combined with the high revenue per barrel for the producer in the States. This implies that elsewhere the scope for additional recovery will frequently be of the same order as the noted differences. Another motivation for re-evaluation of older fields is the realization that irreducible oil saturations measured on core plugs in the past were generally much too high. Consequently, the assumed sweep efficiencies were much too high also, resulting in little incentive for infill drilling or recompletion. A number of factors stimulate the re-evaluation of remaining reserves. Reliable through-casing logging makes the poorly swept zones visible. Detailed structural definition is often possible with 3D seismic. New drilling techniques, like short radius horizontal side tracks, allow economic recompletions of old wells.

The Seria Field was discovered in 1929. Cumulative oil production reached 164X10 6 m 3 (end 1996), approximately 34% of known in-place volumes. A maximum oil production level of 18 780 m 3 /d in 1956 has since declined to 2800 m 3 /d. Most of the more easily recoverable oil has now been produced. Undeveloped oil is concentrated in economically marginal accumulations for which simple subsurface models are an inadequate basis on which to plan further development activities. Instead, dynamic simulation of detailed computer-generated 3D reservoir models is required to optimize reservoir management and evaluate potential development options. 3D seismic data are used to assess undrilled closures and new exploration plays resulting in the development of new hydrocarbon accumulations. Amplitude analysis combined with GST/RST logging has identified areas of unswept oil within the field. Detailed 3D reservoir geological models integrating sequence stratigraphic concepts with reappraisal of core and wireline data are being built using Unix workstations. The models incorporate the results of advanced petrophysical techniques, such as image analysis and resistivity inversion, to quantify net sand, porosity and saturation, and NMR to provide information on moveable oil and permeability. The model forms the input to advanced reservoir simulators where multiple sensitivities can be tested to determine the optimum placement of new wells. Advances in drilling technology have led to the use of horizontal and multi-lateral wells to give the increased productivity necessary for commercial success of such marginal developments. Concurrent engineering effort has led to the field's facilities being rationalized to improve efficiency and reduce costs and the designing of re-usable well jackets for the shallow offshore part of Seria.

We use normal-incidence and wide-angle seismic data recorded on the Faroe Islands to study the crustal structure along two profiles extending east from the islands, across the Faroe shelf and into the Faroe-Shetland Basin. We show that massive basaltic lava flows extend eastward away from the Faroe Islands, having flowed across an older Mesozoic and early Paleocene sedimentary basin, and feathering out near the centre of the Faroe-Shetland Basin. Sediments beneath the basalts reach a thickness of several kilometres in the basin, but do not extend with a resolvable thickness beneath the Faroe Islands. The crustal thickness decreases toward the centre of the Faroe-Shetland Basin, showing that the basement beneath the centre of the basin has been stretched and thinned by a factor of at least two. The Faroe Islands themselves lie on a continental fragment, which had a total thickness of about 10-15 km of igneous rock added as extrusive lavas at the top, and as high-velocity intrusives near the base of the crust at the time of continental break-up in the Paleocene.

The reservoir potential of the Upper Palaeozoic carbonates in the Barents Sea area is primarily controlled by early diagenetic processes. Upper Bashkirian to Asselian shallow platform carbonates deposited in warm, arid to semi-arid climates were dominated by aragonitic organisms and mineralogically unstable aragonite and high-Mg calcite cements and mud. A reservoir model for these carbonates involves extensive dolomitization and dissolution of metastable carbonate during repeated subaerial exposure. The reservoir model is confirmed by drilling and is accordingly regarded as low risk. Artinskian and Upper Permian shallow water carbonates deposited in a cold temperate climate were dominated by calcitic organisms and silica sponges, and associated with calcite cements and mud and chert. A reservoir model for these carbonates involves either preservation of primary porosity in carbonate build-ups or extensive dissolution of build-up marine cement during prolonged subaerial exposure. This model is not confirmed by drilling and is regarded as high risk.

Multidisciplinary studies in the Netherlands have revealed two new phases of late Variscan extensional faulting during the Late Permian. The names Tubantian I and II are proposed in this paper. Tubantian I movements were triggered by rapid deposition and loading of anhydrite upon a differentiated basement, in combination with mild E-W extension. A series of small pull-apart basins and tilted fault blocks formed and local collapse occurred of the Variscan Front. The relief was subsequently filled with carbonates and evaporites of the Z1 (Werra) Formation. Fault movements stopped prior to deposition of the Z2 (Stassfurt) Formation. Tubantian II movements caused uplift and erosion, especially in the southern onshore Netherlands. Contemporaneously, sandy erosional products were deposited in the southwestern offshore area of the Netherlands and the adjacent UK sector and playa-type halites and claystones accumulated in the central parts of the basin. Three features have implications for hydrocarbon exploration: the early formation of fault/dip closed structures shortly after deposition of the Upper Rotliegend; the reorganization of the fluid-flow system and the deposition of contemporaneous sandy deposits.

Unsteady state two-phase flow experiments were performed to check the action of an adsorbed water-soluble polymer on relative permeability and capillary pressure. A selective reduction of the relative permeability to water with respect to relative permeability to oil was observed. Capillary pressure, measured directly on the core, was increased after polymer injection. Since the polymer has little influence on interfacial tension, this trend is interpreted as a reduction of pore size due to polymer adsorption. The validity of this assumption was checked by the investigation of a pore-scale numerical model. Relative permeabilities and capillary pressure were computed for a range of flow rates. Numerical results indicated that the polymer adsorption model (wall effect) successfully reproduces qualitatively the experimental observations.