Asphaltene Gravitational Gradient in a Deepwater Reservoir as Determined by
Downhole Fluid Analysis

Mullins, Oliver C.; Cribbs, Myrt Eugene; Betancourt, Soraya S.; Dubost, Francois Xavier

doi:10.2523/106375-ms

Cited by 27 publications

(31 citation statements)

References 21 publications

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“…One sample appeared to have lost some asphaltene content in the laboratory analysis compared to DFA. 7 The results confirmed that same trends observed in the downhole live fluid data were duplicated in the dead oil samples, i.e. Fortunately a second sample bottle in the same sand was available with the original concentration of asphaltenes.…”

Section: Chain Of Custodysupporting

confidence: 80%

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Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity

et al. 2007

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCompartmentalization is perhaps the single biggest risk factor in deepwater petroleum production. Downhole fluid analysis (DFA) is a new tool to reduce uncertainty associated with reservoir connectivity. Fluid data from DFA logs and various laboratory analyses are studied to elucidate hydrocarbon composition variations in large reservoir sand bodies. This procedure was applied in the Deepwater Tahiti field in the Gulf of Mexico uncovering a large concentration variation of asphaltenes. These asphaltene nanoparticles are shown to be colloidally suspended in the crude oil in agreement with recent laboratory results, and settle preferentially lower in the oil column in accord with the Boltzmann distribution. Relevant fluid features, in this case the asphaltene concentration gradient, are then integrated in a geologic model and used to predict crude oil properties and DFA logs for all hydraulically connected sections of the reservoir. Predicted and newly acquired DFA log data matched for the first production well, establishing that the penetrated sands are likely connected, mitigating compartmentalization risk.This DFA log prediction protocol offers a new method to optimize wireline logging.

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Section: Chain Of Custodysupporting

confidence: 80%

“…7 This asphaltene concentration gradient was used to predict DFA data throughout the field to confirm reservoir connectivity, thereby reducing the key risk factor in the Tahiti development. This fluids map is then used to predict all upcoming DFA log data before a new well is drilled.…”

Section: Introductionmentioning

confidence: 99%

Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity

et al. 2007

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“…[4,22,23] The FHZ EoS has been used successfully to model heavy end gradients in reservoirs for fluids ranging from nearly colorless condensates to heavy oils. [4] For different reservoir fluids, different species (with diameters listed in nanometers) form the asphaltene or heavy end gradient: for the nearly colorless condensates, it is the colored resins (~1nm); [25] for a light oil, it is the asphaltenes molecules (~1.5nm); [26] for black oils, it is the asphaltene nanoaggregate (~2nm); [27,28] and for heavy oil it is the asphaltene cluster (~5nm). [3,29,30] The relatively large asphaltene clusters produce very large asphaltene gradients, with asphaltene concentration doubling every 20 meters of height in the reservoir.…”

Section: Introductionmentioning

confidence: 99%

Characterization of Asphaltene Transport over Geologic Time Aids in Explaining the Distribution of Heavy Oils and Solid Hydrocarbons in Reservoirs

Mullins

Wang

Chen

et al. 2014

SPE Annual Technical Conference and Exhibition

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Asphaltenes are a very important component of reservoir fluids. They have a huge impact on crude oil viscosity and are a Flow Assurance concern. They can undergo a phase transition, giving rise to tar mats that seal aquifers precluding aquifer sweep. Local tar deposits can act as a drilling hazard. Upstructure tar (or bitumen) deposition can occur which can flow with produced light hydrocarbons greatly reducing the productivity index. In EOR, miscible gas injection can also give rise to asphaltene deposition. Characterizing these disparate observations is now performed within a simple overarching framework. Here, we combine asphaltene nanoscience, thermodynamics, and fluid mechanics to model asphaltene-rich fluid flow and asphaltene deposition that occur in reservoirs in geologic (or even production) time. This analysis successfully accounts for extensive measurements in several reservoirs in different stages of similar processes. Reservoir black oils with a late, light hydrocarbon charge experience asphaltene instability. This instability does not necessarily cause precipitation; instead, weak instability can cause a change in the nanocolloidal character of asphaltenes without precipitation. Consequently, this less stable asphaltene remains in the crude oil and is thus mobile. This process can result in fluid density inversions and gravity currents that pump asphaltene 'clusters' in oil over reservoir length scales relatively quickly in geologic time. These asphaltene clusters then establish very large asphaltene and viscosity gradients at the base of the reservoir. If the light hydrocarbon instability event continues, a regional tar mat can form. In contrast, if the light hydrocarbon charge is sufficiently rapid, the displacement of the contact between the original and new reservoir fluids overtakes and precipitates asphaltenes locally producing deposition upstructure often near the crest of the field. In this paper, several reservoirs are examined. Two reservoirs have massive, current gas charge and have bitumen deposition upstructure. Another reservoir is shown to be midway through a slower gas charge, with the asphaltene instability causing migration of asphaltenes from the top to the base of the oil column in the form of clusters creating large asphaltene gravity gradients. Another reservoir is shown to have this process completed yielding a 50 meter column of heavy oil at the base of the oil column underlain by a 10 meter regional tar mat. This integrated analysis enables a much simpler understanding of many production issues associated with asphaltenes and provides a way forward for treating disparate asphaltene problems within a single framework.

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“…Figure 14 shows the huge range of crude oil coloration, in the visible and extending into the NIR; the coloration is closely related to the asphaltene content. [20] Close examination of the spectral region at 1700nm can be used to analyze dissolved methane enabling GOR measurements as shown in Fig. 15.…”

Section: Downhole Fluid Analysis (Dfa)mentioning

confidence: 99%