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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe First Eocene reservoir at Wafra Field was discovered in 1954 and has produced about 290 million barrels of 17-19° API, high sulfur oil.The dolomite reservoir is Eocene/Paleocene age. The average porosity is 35% and the average permeability is 250 md over the gross interval. Well log and core plug porosity values over 45% are common and measured permeability values range up to 5000 md. The First Eocene reservoir has an average depth of about 1300 feet and a gross thickness of about 750 feet. The OOIP is about 9 billion barrels.The reservoir largely consists of dolomitized packstones and grainstones deposited under arid to semi-arid conditions on a shallow, very gently dipping, low to moderate energy inner shelf or ramp setting in a gently dipping, restricted ramp environment. The presence of some interbedded evaporites suggests restriction was occasionally sufficient for the development of hyper-saline lagoons and sabkhas. The shallowing-upward cycles are capped by mud-dominated rocks, hardgrounds and exposure surfaces that are correlative with gamma ray highs that can be easily correlated across the 20 km length of the field and are the basis for the current sequence stratigraphic interpretation.Several full field and small, highly detailed reservoir models have been generated using stochastic workflows to assist management of on-going primary development as well as two steamflood test/pilot projects. The reservoir models utilize the new stratigraphic framework and are constrained by over 285 wells with high quality porosity logs and six wells with high quality core descriptions and core plug data. Model properties were distributed by stratigraphic layer and constrained by layer-appropriate data (or transforms) and layer-appropriate semivariograms. The range parameter for the semivariograms models used in full field static models varied between 1100-2200 m with moderate anisotropy in the direction N120°E. Conversion Factors1 foot = 0.3048 meters 1 meter = 3.2808 feet 1 mile = 1.6093 km

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The Jurassic-age Humma Marrat carbonate reservoir was discovered in 1998. Eleven wells have been drilled to date including several horizontal completions. The gross reservoir interval is about 235 m (730 feet) thick. The reservoir produces from three intervals -Marrat A, Marrat C, and Marrat E. The partially dolomitized lowermost Marrat E interval contributes 75-85% of the total production from zones averaging 20-25% porosity and 10-100 mD permeability. Productive intervals in the Marrat A and C zones average 15-20% porosity and 0.5-2 mD permeability. The current estimated original oil in place is about 500 million bbls.A volumetric uncertainty look-back (1998)(1999)(2000)(2001)(2002)(2003)(2004)(2005)(2006)(2007) has allowed a historical assessment to be made for porosity and water saturation (Sw) uncertainty. This look-back based assessment of porosity and Sw uncertainty allows the impact of increasing quantity of data, changing analytical workflows, and updating interpretations to be examined. Based on the standard deviation or range of the available data at various times in the look-back period, the estimated porosity uncertainty was about ±2-2.5 porosity units (pu) after the first three wells were completed. After two additional wells and integration of core data, the estimated porosity uncertainty was reduced to about ±1.5-2 pu. Data from all eleven wells available at the end of the look-back period showed that the porosity uncertainty reduced slightly to about ±1-1.5 pu. However, a significantly lower estimate for the uncertainty is derived from the variation of the average porosity of the individual well averages after the first three wells were drilled. Using this parameter as a measure of uncertainty provides an uncertainty of ±0.5-1 pu early in field history (after three wells) and ±0.25-0.5 pu at the end of the look-back. Likewise, the uncertainty estimate for Sw decreased from ±15-20 saturation units (su) in 2000 to ±10 su in 2007 based on the standard deviation and range of the data available at each analysis date in the look-back period. Using the change in average Sw of the individual well averages, the uncertainty was ±5-10 su early in field history (after three wells) and ±2-4 su at the end of the look-back' significantly less than that derived from standard deviation or data range. A proposal is made to use the variation of the average of the individual well averages to define uncertainty in cases for which enough data (generally more than 3 wells) is available and there are no changes expected to analytical workflows (e.g. recalculating log derived porosity once core data is available). If changes to analytical workflows are anticipated a more conservative (e.g. larger) estimate for uncertainty should be used, perhaps based on the standard deviation or range of the available data.An original oil in place (OOIP) uncertainty look-back based on a consistent design of experiments-based approach (Meddaugh et al (2006a) is also presented along with a brief discussion of using a normalized uncertaint...