This paper presents a method to condition the permeability modeling of a thin, heterogeneous high-K dolomitized unit. The interval is an important drilling target for field development, so precise permeability modeling is required to optimize well placement and completion designs in order to maximize oil recovery and minimize early water breakthrough. Detailed core observations from 85 wells classify the unit into two groups: Group A, composed mainly of dolostone and Group B, comprised exclusively of calcareous dolostone. Regression analyses of plug porosity-permeability values are characterized by one regression line for each group by which dolostone represents a higher permeability trend relative to calcareous dolostone. Core-plug scaling is used to scale-up the porosity-permeability relationships from core plug- to modelscale (100 m by 100 m cells). The two regression lines accurately capture the permeability contrast within the dolomitized unit. To extend the method into a full-field model, it is necessary to calibrate the well logs to the core data. Comparison of cores with various log responses indicates the porosity log is the most useful tool to achieve this. Group A, characterized by higher dolomite content, is distinguished by a distinct decrease in the porosity due to progressive dolomitization. Porosity logs from 499 wells are interpreted and permeability values are assigned using the regression lines based on the detailed distribution map of both groups. The modeling approach using hundreds of well logs calibrated to cores yields a more detailed picture of the spatial permeability variations of the dolomitized unit. Dynamic data from ongoing history matching is also used to implicitly adjust the first-pass static model.

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The Upper Jurassic Hadriya and Hanifa carbonate grainstone reservoirs in Berri Field, Saudi Arabia, contain large reserves of Saudi Extra Light crude oil. New geologic models of each reservoir have been built using sequence-stratigraphic principles. These new models have a chronostratigraphic architecture which accommodates the facies transitions observed in cores sampled along the ramp-to-basin profile. Each reservoir contains, from oldest to youngest:a highstand systems tract represented by aggrading and prograding grainstones, capped by a type-2 (subaqueous) sequence boundary;a shelf margin wedge systems tract characterized by grainstones showing maximum basinward progradation; anda transgressive systems tract typified by a series of backstepping grainstones capped by a surface of relative drowning. These new models clarify the elements controlling fluid movement within the reservoirs. Introduction Berri field is located about 100 km north of Dhahran in the eastern provence of Saudi Arabia. The anticlinal trap lies partly on and partly offshore, just northeast of Jubail. Of the seven Upper Jurassic reservoirs in this field, the Hanifa and Hadriya are currently under full development because they contain Arabian Extra Light crude (Fig. 1). Both reservoirs have been undergoing peripheral water injection since 1973. In 1988 ARAMCO initiated a joint study with a team from Mobil Research and Development Corporation to construct new geologic models of the Hanifa and Hadriya reservoirs that would eventually be used for reservoir simulation. Sequence stratigraphic principles were used in formulating the new models. Since no high-resolution seismic data was available over Berri Field, sequence stratigraphic interpretations were based solely on core and log data. This included 33 cores and 92 logs in the Hadriya, and 32 cores and 142 logs in the Hanifa. The application of sequence stratigraphic principles led to the recognition of previously undefined reservoir geometries. Subsequent integration of production and engineering data confirmed the importance of these geometries in controlling fluid distribution and movement. The new correlations had an especially profound affect on the three dimensional architecture of the Hanifa reservoir. PALEOGEOGRAPHIC SETTING The Middle Jurassic Arabian Platform was characterized by minimal platform-interior bathymetric relief and by widespread shallow-marine, carbonate sedimentation. Beginning in the Upper Jurassic, however, a series of intrashelf basins and intervening arches were formed (Fig 2). The intrashelf Arabian Basin was separated from the Southern Gulf Basin of Qatar and the United Arab Emirates by the Qatar Arch. P. 489^

A 3-D geologic model of the Hanifa reservoir was constructed using sequence stratigraphic principles and facies to control the distribution of porosity and permeability. The reservoir had been previously interpreted as having "layer cake" stratigraphy based on correlation of similar lithologies and similar appearing porosity inflections. The new geologic model incorporates a field-wide gamma ray correlation over 55 km from the non-reservoir rocks to the main producing area of the field. The gamma ray correlation produced a previously unrecognized reservoir geometry consisting of a high stand systems tract, a shelf (ramp) margin wedge, and a transgressive systems tract. This model represents our first 3-D geologic model based on sequence stratigraphy. This geologic model has been used successfully in reservoir simulation and field operations.The reservoir consists of skeletal sands and stromatoporoid boundstone complexes to the north that grade to non-reservoir mudstones to the south. The reservoir was divided into 45 geologic layers. Core descriptions led to mapping facies distribution within each geologic layer. A 3-D lithofacies model was constructed and used as a template to calculate and assemble porosity and permeability models. A water-saturation model was also constructed based on facies specific J-functions. The geologic horizons were then grouped into 20 flow layers as the geologic front end into reservoir simulation. 517The resulting geologic model has improved the Hanifa reservoir simulation by defining previously unrecognized reservoir geometries and providing the detailed resolution that enabled engineers and geologists to identify and understand the geologic attributes controlling fluid movement. The flood front has moved preferentially through grainstones in the highstand systems tract by crossing layer boundaries. Fluid flow has been impeded within layers that are dominated by boundstones, wackestones or mudstones.

A new generation geologic model for a giant Middle East carbonate reservoir was constructed and history matched with the objectives of creating a model suitable for full field prediction and sector level drill well planning. Several key performance drivers were recognized as important factors in the history match; 1) unique carbonate fluid displacement; 2) data validation and horizontal well trajectory issues; and 3) distribution of high permeability streaks. Ultimately a full field history match consisting of more than 1000 well strings and several decades of history was achieved using detailed distribution of the high permeability streaks, while honoring measured core poro-perm relationships, lab-validated displacement curves, and well test data. This paper discusses the role of the geometry and the vertical distribution of the high-permeability streaks in the history matching of a giant offshore carbonate reservoir. Specifically, the modeling of the high-permeability streaks – which consist of thin rudist and algal rudstone, floatstone, and peloidal grainstone, with abundant, well-connected inter-particle porosity - became possible after extensive revamping of the reservoir rock type model, updating well descriptions, and a detailed zonal mapping of the high permeability streaks and dolomitic zones. The areal and vertical model resolution was doubled over the previous models to accommodate the internal sub-layering of the upper four reservoir zones in order to capture the thin (~1.4 ft) high-permeability streaks. During the history match, local modifications of the high-permeability streaks were the integral part of the feedback loop between the simulation engineers and geoscientists that kept the common-scale simulation model and geologic model synchronized. The final history match was validated by extensive analysis of the models’ vertical conformance as compared to production logs. This approach made it possible to construct a more heterogeneous model than previous models; while honoring both field KH and matrix poro-permeability without local permeability multipliers. The combination of these features provides a higher confidence model of long term well injectivity/productivity.

The subject reservoir is a heterogeneous carbonate formation in a giant field located offshore Abu Dhabi. Five gas injection pilots were initiated in late 2001 in the Eastern, Central and Western parts of the field both as secondary and tertiary recovery methods to evaluate the benefit of gas injection for pressure support and for recovery improvement. With less than 10% of HCPV gas injection, the pilots to date have provided valuable insight on production performance and pressure support, gravity override, swelling effect and flow assurance issues (such as asphaltene deposition) in the field. Using a 3D compositional model, a sector modeling study was carried out for comprehensive evaluation of the pilot performance to date and to predict definitive results within reasonable time frame (3-5 years) which will have ramifications on long-term full field development decisions. Additionally, the objectives of simulation efforts were to evaluate different recovery processes (gas/water/WAG) and assess key reservoir uncertainty (volumetric sweep) due to reservoir heterogeneity (high permeability streaks). Initially, the sector model was history matched with nine years of pilot performance while both reservoir heterogeneity and well spacing sensitivities were tested in the model. The history matched sector model was utilized to predict performance under different operating conditions using both gas, water and water alternating gas (WAG) injection methods. This paper describes the pilot performance, field observations and results of a sector model study including history match, sensitivity and predictions under different injection scenarios on two of the pilots. Based on the performance and surveillance data gathered on the two pilots and sector modeling study, it was established that both pilots have met their objectives and can be concluded. Through the integration of field observations and sector modeling work, the study provided valuable insight on optimum recovery processes, well spacing and well completion requirements for long-term field development.

Numerical simulation models have been used to optimize oil recovery since the 1960's. Typical steps to create a simulation model include 1) building a static model based on all available geological and petrophysical data; 2) history matching the static model to tune it to the available production and measured data; and 3) using the conditioned model to design drill-wells, predict pressure evolution, and forecast flow streams for business decisions. Today it is generally accepted that the best models result from using interdisciplinary teams to ensure geologic consistency is maintained during the history matching modifications – e.g. Sibley (1997), Landis (2005). We discuss herein a unique approach to efficiently manage and expedite the history matching of a giant carbonate reservoir using a team of simulation engineers. The workflow was developed based on domain decomposition principles to divide the problem into manageable sector models with coordinated updates between the sector and full field model to obtain the full-field history match. With this approach, dynamic history matching is divided among many simulation engineers in a way that maintains the base geologic model, vets regional modifications, and transmits local lessons to the full-field model. The workflow relies on fast extraction, creation, and management of sector models (or subdomains) from the full field. Each sector is linked to the full field by incorporating flux boundary conditions obtained from either a larger sector model or the full-field model. The proposed approach allows for the acceleration of the history match by effectively dividing the work among a team of simulation engineers. The "sector" approach of making smaller models from one large model speeds up the model build and run times making it convenient to have the multiple iterations necessary to achieve a satisfactory history match in a complex, high-contrast flow strata geologic environment. The goal of the work was to reduce the time to achieve the history match to one year, as opposed to the previous experience requiring several years for similarly sized models. Some critical advantages and lessons from the workflow will be discussed through its application using actual history matching examples from a giant offshore, Middle Eastern, carbonate reservoir having over four decades of production history.

It is well known that the permeability of porous media represents a first order control on fluid flow in hydrocarbon reservoirs and that the magnitude of the permeability often depends on the rock volume under consideration. Core plug permeability does not necessarily equal whole core permeability and permeability from core may not necessarily reflect well test permeability. Each of these disparate data sources measures permeability at a particular scale. For the purposes of reservoir modelling, the permeability systems characterizing a giant offshore oil field have been broadly categorized as either matrix permeability or excess permeability. Matrix permeability further subdivides into two categories based on the abundance and type of microporosity. Excess permeability subdivides into three subcategories depending whether it is the result of depositional processes emplacing anomalously high permeability storm beds (HKS or high permeability streaks), diagenetic processes creating dissolution enhancement of permeability, or fractures. Although not all these permeability systems are active in any reservoir interval, each reservoir interval possesses at least two if not three of these systems. The multi-scale nature of permeability arises because of 1) differences in the spatial extent of these permeability systems and 2) permeability contrasts between the systems.Several techniques have been developed and will be explored in this paper that attempt to account for the influence of multi-scale permeability systems on reservoir performance behaviour. In what might be the simplest case, the mixture of permeability systems includes only matrix permeability without significant microporosity and excess permeability resulting from HKS. In this case, matrix permeability was modelled independently of excess permeability creating significant short-range permeability contrasts that better predicted reservoir pressures and water movement in the reservoir during history -matching. In another case with the same type of matrix permeability, the excess permeability represents the contributions from a mixture of fractures and HKS. In this case, matrix permeability was also modelled independently of excess permeability. Estimates of the relative contributions of HKS and fractures to excess permeability were tested as a history-matching parameter. Ultimately, this approach to characterizing permeability attempts to capture some of the rudimentary aspects of a dual permeability model without incurring the associated computational expense.