Utilizing Welltests in Determining the Drive Mechanism and Threshold Pressures Between Three Communicating Reservoirs

Zubari, Hisham; AL-Awainati, M.Y.

doi:10.2118/37795-ms

Cited by 5 publications

(3 citation statements)

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“…• Within a given reservoir, pressure-dependent communication across fault planes may start to leak fluids when a sufficient pressure difference--the pressure threshold--is applied to both sides of the fault (Zubari and Al-Awainati, 1997). In the case of Central Haradh's western flank, the threshold pressure concept may be applied to a fault zone vertically linking the hydrostatic Jurassic Arab-D reservoir and a charged shallower aquifer such as the Cretaceous Biyadh (Figure 29).…”

Section: Discussionmentioning

confidence: 99%

Tilted original oil/water contact in the Arab-D reservoir, Ghawar field, Saudi Arabia

Stenger¹,

Pham²,

Al-Afaleg³

et al. 2003

GeoArabia

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A review of the electrical logs, fluid properties, and production history of 195 flank wells drilled in the Arab-D carbonate reservoir of the Ghawar field, Saudi Arabia, showed that the original oil/water contact was regionally tilted. The contact was about 200 ft higher in the southern Haradh sector than in the northern Shedgum and ‘Ain Dar sectors. In Haradh, the fluid contact was also locally tilted down from west to east by as much as 800 ft. In the reservoir, the oil and aquifer densities changed from lighter oil and denser water in the north to lighter water and denser oil in the south. Decreasing methane content caused the increase in oil density and a reduction in the water density was the result of a salinity decrease. The evolution of fluid densities was closely correlated to a decreasing regional-scale geothermal gradient, probably indicating that temperature controlled the distribution of fluid densities. Simple analytical calculations showed that the magnitude of the observed tilt of the original oil/water contact from north to south might be explained by changes in fluid densities. On the western flank of central Haradh, the Arab-D reservoir water was anomalously young and fresh and this created a large salinity gradient between the western and eastern aquifer legs. This anomaly was explained by pressure-dependent vertical leakage along the Wadi Sahba structural trough between the Arab-D reservoir and the shallower Biyadh aquifer. Consequently, the integrity of the Hith Formation seal above the Arab-D reservoir might be locally compromised under particular conditions. A full-field reservoir simulation model, specific geological features, and examples from the technical literature supported a static interpretation of the tilted original oil/water contact in the Arab-D reservoir of Ghawar through the combined effects of changes in oil and water densities.

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Section: Discussionmentioning

confidence: 99%

Tilted original oil/water contact in the Arab-D reservoir, Ghawar field, Saudi Arabia

Stenger¹,

Pham²,

Al-Afaleg³

et al. 2003

GeoArabia

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“…Earlier attempts to conduct buildups in the gas lifted wells were complete failures due to the noise caused by the gas lift gas in the Early and Middle Time Region. So a new innovative procedure was designed to utilize the gas-lift gas at the wellhead to carry out a falloff test 5,6,7 . A known quantity of gas was injected into the formation over a few days followed by shutting in the well for a falloff test.…”

Section: Well-tests In Ahmadi Reservoirmentioning

confidence: 99%

“…Furthermore, the fault throws and the areas of communication between Ab and the underlying zones controlled the degree of communication and the type of fluids being introduced into the Ab zones. Earlier studies has shown that Aab zone is continuously receiving fluid and pressure support in certain areas from the underlying higher pressure Mauddud zone (which is undergoing gas injection 8,9 ) through an intermediate sandstone layer, the Wara sandstone which exist in the form of erratic sand lenses distributed irregularly all over the field 6,7 .…”

Section: Production Data Analysismentioning

confidence: 99%

Integrated Reservoir Connectivity Study of Ahmadi Fractured Reservoir in Bahrain Field

Al-Muftah

Murty²,

Lemaux

2009

SPE Middle East Oil and Gas Show and Conference

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This paper describes how the fracture model for Ahmadi was incorporated into a single and dual porosity simulation model. It highlights the approach and methodology that has been used for understanding the reservoir connectivity and its drive mechanism. In addition, the effect of dual porosity model in improving the initial history match of the reservoir performance and its recovery mechanism has been studied.The two Ahmadi carbonate reservoirs in Bahrain Field (Aa and Ab) are thin, highly faulted and irregularly-fractured. The complexity of these reservoirs has prevented an efficient recovery with average production of wells to 15 Bopd. This has prompted a detailed integrated study to fully understand the recovery mechanism and to increase the wells' productivity.A conceptual model has been developed for the reservoir connectivity of Ahmadi reservoirs by integrating static and dynamic data. This comprehensive study that integrates transient welltesting and production data with cores and image logs to map fracture network derived using seismic facies has resulted in improving the understanding of reservoir connectivity and flow mechanism. This was accomplished by building Discrete Fracture Model (DFN) that was tuned and validated using sector local well test models to match KH and pressure responses.In order to reduce uncertainties in the model, different scenarios were built for different fracture intensity and aperture to derive appropriate parameters to pass to reservoir simulator for full field simulation. DFN model output was used in both single and dual porosity models to obtain production performance of the reservoirs.

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Reserves Estimation and Classification Challenges in a Mature Oil Field

Zubari¹,

Kumar²

2007

SPE Middle East Oil and Gas Show and Conference

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Estimation of hydrocarbon reserves is governed by natural, technological and economic factors. Re-estimations and reviews continue almost till the end of exploitation in many instances. Estimation of oil reserves, when a field is in its initial stages of development is a relatively easy task. The estimation will not invite critical or close scrutiny, as the oil production at that stage is far lower than the reserves calculated. However as the field matures and the cumulative oil production approaches the estimated value of reserves, the accuracy in the estimation of reserves becomes crucial and more important. Also the estimation process itself is a challenging task, in the light of uncovering geological complexities and reservoir dynamics during the development and the exploitation methods employed to produce the oil. Bahrain field, the first discovery in the Arabian Gulf region, has been on production since 1933. It is a multi-stacked field with 16 oil and 4 gas reservoirs. Most of them are carbonate reservoirs. The nature of the fluids varies from tarry oil in the Aruma formation occurring at shallow depths to dry gas in the deep Khuff zones. The geology of the field is complex with a large number of faults on the structure. The major oil zone Mauddud - an oil wet system -has been on gas injection from 1938. The gas injection has lead to the transfer of oil and gas into layers above and below through the faults. Though many reservoirs of the field have reached mature stage, there are some zones containing oil resources still unexploited due to the heterogeneities, complex nature of the fluid distribution, unfavorable rock-fluid characteristics, compartmentalization, thin oil rim overlain by gas and underlain by water, etc. This paper brings out the challenges posed by the above situations while attempting to estimate and classify oil reserves. Introduction Bahrain field, discovered in 1932, has 16 oil reservoirs and 4 gas reservoirs (Figure: 1).1,2 The fluid content of the reservoirs vary from the tarry oil in Aruma to dry gas in the Khuff and pre-Khuff zones (Figure: 2). Most of the above reservoirs are carbonates and some of them are clastics. The carbonates of the Cretaceous have shale limestone sequences, while the Jurassic and Precambrian Khuff have dolomitic limestone embedded in anhydrites. Based on the depth of occurrence, the oil reservoirs have been separated into three groups. The shallow zones are the zones from Aruma to Ab, which are poor producers in general. The middle zones comprise of the Wara sand Ac, the major oil producer -Mauddud limestone and the Nahr Umr sands. These are prolific reservoirs and are known as Bahrain zones. The remaining deeper reservoirs, Kharaib, Arab zones and Fadhili are termed as Deep zones, which have moderate productivity. The geology of the field is extremely complex with a large number of faults, especially in the shallow and Bahrain zones. Also some reservoirs are fractured. In a single field, there are large variations in the rock properties and the fluid properties. This makes the work of estimating and classifying the oil reserves a challenging task.

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Utilizing Welltests in Determining the Drive Mechanism and Threshold Pressures Between Three Communicating Reservoirs

Cited by 5 publications

References 0 publications

Tilted original oil/water contact in the Arab-D reservoir, Ghawar field, Saudi Arabia

Tilted original oil/water contact in the Arab-D reservoir, Ghawar field, Saudi Arabia

Integrated Reservoir Connectivity Study of Ahmadi Fractured Reservoir in Bahrain Field

Reserves Estimation and Classification Challenges in a Mature Oil Field

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