Metre-scale lithologic cycles, visible in core and on logs from Maastrichtian chalks of the Dan Field, were examined to determine their mechanisms of deposition and relation to hydrocarbon production. The lower parts of cycles consist of porous, cream-coloured, largely non-stylolitic, commonly laminated chalk with limited bioturbation (mainly escape burrows). Cycles are capped by thinner intervals of white to grey, hard, stylolitic chalk with concentrations of bioclastic material, intense burrowing and few preserved primary sedimentary structures. The cycle caps contain nearly twice as much Mg as compared to the more porous parts of cycles and also have slightly larger d 18 O values (A4á1& for the caps; A4á4& for porous zones). There is a signi®cant reduction of average cycle thickness, as well as total thickness of the Maastrichtian chalk section, from SW to NE across the Dan Field. The cycle thinning largely results from a reduced thickness of porous chalks from the lower parts of cycles and thus is re¯ected in lower average porosity and permeability on the NE side of the ®eld. These data indicate that episodic winnowing removed ®ne-grained constituents from highstanding northeastern areas. Porous cycle bases were deposited at relatively high rates that precluded complete bioturbation; preserved laminae, coupled with escape burrows, re¯ect episodic sediment in¯ux in areas that¯ank the sea¯oor highs. Cycle tops apparently accumulated more slowly (throughout the region, but especially on sea¯oor highs), perhaps because of reduced productivity of planktic organisms. Slower sedimentation allowed more complete bioturbation and destruction of sedimentary structures, and also led to incipient high-magnesium calcite sea¯oor cementation (suf®cient to yield ®rmer sediment and enhanced burrow preservation, but not to form true hardgrounds). Thus, the elevated magnesium contents and reduced porosity of the cycle caps re¯ect very early diagenetic processes that were only partially modi®ed by burial diagenesis.Rates of chalk deposition, as inferred from physical and geochemical evidence, appear to be a signi®cant control on reservoir characteristics in North Sea chalks. The highest average porosities and permeabilities are found in areas with the highest sediment accumulation rates where sea¯oor diagenesis is minimized. Topographic depressions at the time of sedimentation can thus be expected to have the best production characteristics, and synsedimentary topographic highs should have the thinnest sections and the poorest petrophysical properties.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMaersk Olie og Gas AS has as operator for the Danish Underground Consortium (DUC) discovered and initiated the development of the Halfdan accumulation located in the southern part of the Danish North Sea. The accumulation comprises oil and gas in a low permeability chalk reservoir located outside structural closure. This paper describes how the phased, fast track development of Halfdan was planned and executed while testing a new concept for constructing an aligned sweep pattern.Tilted oil-water and gas-oil contacts across the Halfdan area are indicative of non-equilibrium conditions. The nonstructural trapping in the Halfdan area is provided by a combination of up dip thinning of the hydrocarbon bearing section, late structural tilting and the slow re-adjustment caused by the low permeability.Accelerated a nd stepwise development was pursued to allow continuous optimisation of the development in light of the significant uncertainties associated with the fluid distribution and reservoir production characteristics. Appraisal drilling from a template and tie-back of the appraisal wells to temporary production facilities via the drilling rig and early deployed pipelines enabled production from the Halfdan 10 months after finalising the discovery well. Furthermore, a temporary water injection package installed on the drilling rig enabled evaluation of water injection before the installation of permanent facilities including determination of displacement efficiency, fracturing pressure and induced fracture orientation. Halfdan was produced through permanent facilities less than 18 months after finalising the discovery well.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractComplex pore size distributions encountered in carbonate rocks have a large impact on the fluid flow characteristics of carbonate reservoirs. Consequently, although nuclear magnetic resonance (NMR) has been frequently used for characterization of clastic reservoirs, it has not been widely applied to carbonates. This paper describes a case study from the Shuaiba carbonate reservoir of the Al Shaheen field, offshore Qatar. Core data from a study well were used to establish an NMR carbonate rock-typing model for permeability estimation. The rock-typing model was verified in the study well with a wireline NMR logging tool. Core analysis included thin-section petrography, NMR surface relaxivity, mercury injection, porosity and permeability measurements. NMR distributions determined on core were partitioned and linked to pore body size and pore throat size distributions. Several rock types were also defined based on their NMR and petrographic characteristics. To improve permeability prediction in the cored interval of the study well, an NMR-based permeability equation was derived. The core-calibrated NMR carbonate rock typing model was applied to noncored sections of horizontal wells drilled in the Shuaiba formation having logging-while-drilling (LWD) NMR data to improve rock typing and permeability estimation, thus, providing valuable input data for reservoir modeling.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractComplex pore size distributions encountered in carbonate rocks have a large impact on the fluid flow characteristics of carbonate reservoirs. Consequently, although nuclear magnetic resonance (NMR) has been frequently used for characterization of clastic reservoirs, it has not been widely applied to carbonates. This paper describes a case study from the Shuaiba carbonate reservoir of the Al Shaheen field, offshore Qatar. Core data from a study well were used to establish an NMR carbonate rock-typing model for permeability estimation. The rock-typing model was verified in the study well with a wireline NMR logging tool. Core analysis included thin-section petrography, NMR surface relaxivity, mercury injection, porosity and permeability measurements. NMR distributions determined on core were partitioned and linked to pore body size and pore throat size distributions. Several rock types were also defined based on their NMR and petrographic characteristics. To improve permeability prediction in the cored interval of the study well, an NMR-based permeability equation was derived. The core-calibrated NMR carbonate rock typing model was applied to noncored sections of horizontal wells drilled in the Shuaiba formation having logging-while-drilling (LWD) NMR data to improve rock typing and permeability estimation, thus, providing valuable input data for reservoir modeling.