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Reservoir characterization is one of the most challenging subjects in Carbonate reservoirs. In this study Flow Zone Index, Winland and initial water saturation methods were used to classify rock typing in an Iranian oil field located in the south-eastern region. In addition, the predicted initial water saturation along with log and core data was used for capillary pressure estimation. The studied field is a Cretaceous fractured oil bearing reservoir composed of tightly packed limestone characterized by high porosity but poor permeability with a thickness of 55–65 meters throughout the reservoir. The matrix permeabilities and porosity are in the range of 0.01–150 md and 5–40 percent respectively. The oil gravity is 21.5 degree API. Conventional Core data were first used to define the rock types for the cored intervals in which nine district rock types were defined. Furthermore, the FZI (Flow Zone Index) log was also generated based on the permeability which was obtained from FMI (Full-bore Formation Micro Imager) and porosity logs of cored and un-cored intervals. In addition, SLMP (Stratigraphic Modified Lorenz) plots were generated for the purpose of identifying flow zone and barriers in each well. Also, Winland method was also used for the same purpose. The results of SLMP were consistent with Winland result and FZI. The Scanning Electro Microscopy Photomicrographs of the obtained rock type were studied and found to be consistent with the finding of this work. Further, the available initial water saturations obtained from log data were classified in three groups and found to consistent with FZI and Winland methods. Based on the DRT (District Rock Type) obtained from the FZI method a correlation between initial water saturation from the log and DRT was developed for the purpose of initial water saturation prediction. The generated data was used for the capillary pressure and relative permeability estimation. The generated capillary pressure and relative permeability were consistent with available scale data and provided sufficient Pc curve for the uncored intervals. Introduction Reservoir rock typing is a process for the classification of reservoir rocks into distinct units. If the rocks are properly classified and defined, the real dynamic characteristics of the reservoir will be provided in the reservoir simulation model. Several investigators 1–5 have noted the inadequacy of classical approach and have proposed alternative models for relating porosity to permeability. From the classical approach it can be concluded that for any given rock type, the different porosity/permeability relationships are evidence of the existence of different hydraulic units. In fact, several investigators 4–5 had come to similar conclusions about porosity/ permeability relationships. Various quantitative rock-typing techniques are presented in the literature; Winland method, RQI and Swi methods are used more frequently 6–12. However, the RQI method appears to be more widely used 13. The in cooperation of log data with this statistical and neural network modeling has enhanced the RQI application 13&14. Conventional cores are correlated to the log data for purpose of prediction the uncored intervals. This approach is very useful for fields with limited data.

Improving oil production is one of the most challenging subjects in carbonate reservoirs, especially in the case of thin formations when reservoir pressure is close to saturation pressure with undesired well locations. In this study water injection was used to mitigate gas production in a thin reservoir with high gas oil ratio for the purpose of optimizing oil production. The studied field is a cretaceous oil bearing reservoir composed of tightly packed limestone characterized by high porosity but poor permeability with a thickness of 55-65 meters throughout the reservoir. The matrix permeabilities and porosity are in the range of 0.01-150md and 5-35 percent respectively. The oil gravity is 21.5 degree API and reservoir pressure of 1700psia which is close to bubble point pressure of 1492psia. The produced wells were drilled in top layers of the reservoir. A full field model was constructed to determine the optimal production strategy and applied reservoir management with available produced well locations. Two possible scenarios; namely, natural depletion and water injection were compared. Results indicated that water injection yields better recoveries than natural depletion. Different scenarios of injection well location, well orientation and mechanism of injection were considered. Horizontal injection and production wells located at same layer were found to maintain reservoir pressure, prevent gas production, and increase oil recovery. Depleted regions near the producers were found to play a major rule on the success of the project. The enhancement of oil recovery was improved to 37 percent in the case of water injection with the implementation of proper reservoir management.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIncreased oil and particularly gas production may be achieved in waterflooded reservoirs by stopping further water injection, and depressurising the reservoir to release solution gas. Pressure depletion may be accelerated by back producing injected brines. However, there is the possibility that these brines may cause formation damage by mobilising fines or deposition of inorganic scales. Scale deposition in production wells may also occur as a result of pressure depletion, with calcite scales being precipitated when the system drops below the CO 2 bubble point pressure. This paper discusses the assessment and prediction of scale related formation damage problems that are likely to occur during depressurisation of a case study field. The potential for the specific problem arises from the formation of barium sulphate scale as a result of mixing of injected and formation brines during production. Data used in this study includes well brine chemistries and an existing finite difference reservoir simulation model of the field depressurisation, which was used to calculate the mixing of injected and formation brines, and the movement of the mixing and temperature fronts during waterflooding and subsequent depressurisation.This study has determined that the behaviour of the scaling potential for each well in this field is different. Also, the degree of scaling, both deep within the reservoir where it does the least damage, and around the wellbore (for both injectors and producers) where it may adversely affect production, can be predicted by detailed modelling using both conventional and reaction-flow simulations. Former injectors converted to water production or infill wells drilled in the aquifer for pressure depletion may experience an increase in the scaling potential that significantly impacts the economics of the project because of the need for extensive prevention (inhibition) treatments. The increased scaling potential in these wells is a result of the dynamics of brine mixing in the reservoir, the lowering of reservoir temperature in the vicinity of injection wells during waterflooding, and the large volumes of water that require to be produced to achieve depressurisation. The magnitude of the scaling problem and the economic impact are lower for the production wells due to lower water production rates and higher temperatures.

Summary Increased oil and particularly gas production may be achieved in waterflooded reservoirs by stopping further water injection, and depressurizing the reservoir to release solution gas. Pressure depletion may be accelerated by backproducing injected brines. However, there is the possibility that these brines may cause formation damage by mobilizing fines or deposition of inorganic scales. Scale deposition in production wells may also occur as a result of pressure depletion, with calcite scales being precipitated when the system drops below the CO2 bubblepoint pressure. This paper discusses the assessment and prediction of scale-related formation damage problems that are likely to occur during depressurization of a case study field. The potential for the specific problem arises from the formation of barium sulphate scale as a result of mixing of injected and formation brines during production. Data used in this study include well brine chemistries and an existing finite-difference reservoir simulation model of the field depressurization, which was used to calculate the mixing of injected and formation brines and the movement of the mixing and temperature fronts during waterflooding and subsequent depressurization. This study has determined that the behavior of the scaling potential for each well in this field is different. Also, the degree of scaling, both deep within the reservoir where it does the least damage and around the wellbore (for both injectors and producers) where it may adversely affect production, can be predicted by detailed modeling using both conventional and reaction-flow simulations. Former injectors converted to water production or infill wells drilled in the aquifer for pressure depletion may experience an increase in the scaling potential that significantly impacts the economics of the project because of the need for extensive prevention (inhibition) treatments. The increased scaling potential in these wells is a result of the dynamics of brine mixing in the reservoir, the lowering of reservoir temperature in the vicinity of injection wells during waterflooding, and the large volumes of water required to be produced to achieve depressurization. The magnitude of the scaling problem and the economic impact are lower for the production wells because of lower water production rates and higher temperatures. Introduction A number of mature waterflooded fields are candidates for tertiary recovery by depressurization, as is currently occurring in the Brent field, North Sea. Pressure depletion is achieved by stopping water injection and producing from the aquifer as well as the hydrocarbon-bearing strata. Solution gas in the residual oil, previously bypassed oil rims, and attic oil is then released (Mackay et al. 2002). The decision to implement depressurization in any waterflooded field involves significant economic considerations. By evaluating the scaling tendency, the uncertainty and cost resulting from potential losses from scale-related deferred oil and gas production may be minimized. This process should involve a thorough review of the current scale management practice, followed by a detailed study of which parameters will change as a result of depressurization. A candidate field for post-waterflood depressurization has been studied to identify the potential impact of scale damage on production. A predictive reservoir simulation model, designed specifically to evaluate depressurization (Drummond et al. 2001), was adapted to study the changes in some of the parameters that are expected to impact scale precipitation. This paper describes the application of this model of reservoir depressurization to evaluate the scaling potential in production wells and in former injection wells when they are used for back production of injection seawater. The calculations performed using the conventional finite-difference flow model do not incorporate reaction calculations, although they may be used to demonstrate the propagation of the mixing zone. To model scale precipitation, the consequent ion loss, and permeability impairment, a commercial reaction transport simulator was used.