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For each of the following fluid types, select a North American field which contains these fluids and describe the actual or expected fluid properties in as much detail as possible (for example oil and gas densities and viscosities, gas oil ratio or condensate gas ratio, saturation pressure and temperature etc.):

(a) Heavy oil

(b) Light (volatile) oil

(c) Gas condensate

Explain how the fluid property type influences field development plans (production rates, recovery factor, artificial lift requirements etc.) and use the above fields as examples.

(a) Explain the three stages of hydrocarbon recovery from an oil reservoir (primary, secondary and tertiary) and how these affect production rates (oil, water and gas), reservoir pressure and the estimated ultimate recovery of oil.

(b) Select two North Sea oil fields, one with a high recovery factor (> 60%) and one with a low recovery factor (< 30%), and explain in detail the key factors that have resulted in such reservoir performance.

Question 1

Fuel resources come in different forms leading to its transformation from the natural form. Its classification into heavy, light oil and gas condensate is a complex process. The discovery of heavy oil in the US fields spreads across a number of years. The Mexican Gulf deposits represents an old field that stands out among the largest in in the region (Ceron, 2017)

The heavy oil has different fluid properties ranging from diverse viscosity of live oil and a gas-oil ratio (Zuo, et al., 2010). This is extremely heavy and contains higher molecular saturates of non-polar hydrocarbons. This also features paraffin in aliphatic cyclic mode. Its heaviness explains the slower oil flow within the reservoirs. This oil category has a lower API ratio or Gas Oil Ratio. Such complex differences make the discovery process a difficult one because of the sensitivity effects. For example, the heavy oil shows variations in gas components, which explain the uncertainties in measurements. This is the high-density crude oil with temperatures below 10° as shown in the table below. Its viscosity is also low and its category range includes bitumen, crude and heavy oils.

Light oil is volatile and depicts a low-density liquid petroleum fluid. With a lower viscosity and increased hydrocarbon ratios, the Gulf of Mexico oil field has crude oils with an API of 27 ° - 38°. At 20°, the oil is at medium density. Its high API gravity means higher gas oil ratio and low density, which allows it to flow freely at room temperatures (Ghannam, et al., 2012). Its high hydrogen level gives it a sweet sulfur property. The Mexico’s Isthmus is a variation of the light crude oil with 89.2% oils and 8.1% alkanes. This hydrocarbon evaporates at between 28% and 60% rates (Environment Canada, 2017). Light oil is permeable in flow because it is light in weight. It lower molecular components of below 120 explains this phenomenon. When this goes below 43, it becomes a gas condensate. Light oil also has a high shrinkage rate.

This is gas fluid with a gas oil ratio of more than 900 giving it very low viscosities. The Mexican Gulf gas condensate is bubbly and shiny (Houston, 2017). This liquid combination of gaseous hydrocarbons has densities of 0.75-0.80gr/cm3. It comprises of wet and dry gas with a molecular weight that is average, the condensate gas at this field has a gas condensate ration (GCR) of over 435 Pressure Volume Temperature (PVT) (Jorge, et al., 2014). The Gulf of Mexico’s gas condensate dew point pressure yields as much as 50bbls/MMSCF. This field also indicates high carbon bubble Points. It has a maximum retrograde condensation (MRC) of 80% leading to vaporization. The condensate gas shows differences in permeability and between liquid and solid hydrocarbons (Kennedy, et al., 2012). The presence of carbon dioxide leads to reduction of free gas, which has a low viscosity.

Question 2

Fluid reservoir, gas condensate factors and gravity interact to determine the production procedures (McCain, et al., 2011). Mature fields like the Mexico Gulf reservoirs require advanced technology drilling in order to access different oil categories. The properties are necessary guides to the discovery of new oil fields. In this region, the use of high pressure and temperature support the process of accessing the gas points.  Controlling the conditions of a gas field reduces the production of free gas. The figure below show drops in oil production at Lucius field in the Gulf of Mexico caused by the rising water cut.

Figure 1: Gulf of Mexico trends in oil production influenced by water break in the fields (Kaplan, 2017)

Fluid properties provide a methodology for the separation of oil and gas fields. The high-pressure bubble points are indications of oil saturation. In some fields, such as the Gulf of Mexico increase in pressure in the oil viscosity is in line with the pressure. This leads to the determination of the viscosity bubble point and dead viscosity levels. The viscosity determines the fluid resistance and gravity flow.  These are important in detecting any contamination and oil quality. The fact that light oil has a quick flow gives it an edge because of its greater yield and (Demirbas, 2011). Having insight into these provides direction for oil recovery. The viscosity fluid property and temperature dependence influences the rate of production by preventing oil loss, mechanical wear, friction and failure. These are important in the management of the internal and external flows.

Since natural oil is, a nonrenewable source of energy the recovery factor provides estimates of the oil and gas through appropriate methods of obtaining conventional and heavy oils (Zuo, et al., 2010). Fluid properties help to determine the extraction and consumption by analyzing its formation. The Gulf of Mexico has more than 1200 active and depleted fields. These require different models of estimating and optimizing the oilfields (Wu, et al., 2016). The chemical factors in the in heavy, light oil and gas condensate dictate the manufacture and development of oil for energy production. The Gulf of Mexico has a production history in which the wells shrink due to overconsumption. Improved technologies have the capacity to identify fluid weight for appropriate strategies on the changing condition of the wells.

Artificial lift requirements are necessary for the extraction of oil in a field. Understanding the fluid characteristics highlights differences in API gravity for effective extraction. The figure below shows API gravity of below 6.5° for extra heavy oil. These properties indicate when it is appropriate to mine oil and gas through different pumps. Increased pressure pushes the crude oil to the surface through sucker or hydraulic lift pumps. The application of pressure at the bottom encourages the gas to flow upwards (Guo, 2011). With a high viscosity of more than 10, 000 centipoise (cP), the extra heavy oil shows differences with heavy oil which is less than 100cP. Comparing the natural flow alienates the oil in its natural state for easier production and recovery.

Fluid Properties of Heavy and Light Oil in North American Fields

Figure 2: Surface formation of crude oil, adopted from Rigzone (2017)

The formation volume factor (VF) shows the reservoir condition by checking the fluid temperature and pressure dynamics (Ambrose, et al., 2012). Changes in the gas VF emanate from the gas and liquid phases. The Vaporized Oil Ratio indicates the gas condensate at the Mexican Gulf for the separation approaches. Data from the subsurface samples distinguishes between the hydrocarbon and oil variants through the properties. By relating the water density with the gas oil ratios a petroleum, company in Mexico is able to develop the scale and instruments for the production of light, heavy oil and gaseous forms. This also creates an equilibrium through the density and density production levels.

  • Three stages of hydrocarbon recovery from an oil reservoir

The primary, secondary and tertiary stages of hydrocarbon oil recovery in a reservoir describes the mechanisms as well as techniques used in the recovery process. The preliminary stage or natural approach is a blend of different approaches featuring the solution gas, gas cap, water, gravity drainage and mixed drives. The removal of gas from an evolved solution comes from the gas and aquifer expansion. The gravity drainage is a boost to the gravity drainage. Step 1 is the solution gas drive, which involves a process of expansion within the surface rocks characterized by water and gas pressure. It also defines the GOR and the production of fluid variations for the oil recovery to ensue. The introduction of artificial lifts mitigate the gas production at the bubble point through the reduction in reservoir pressure and production of water. Step 2 works on the production of the gas-oil contact (GOC) by increasing GOR and efficiency for increased oil production. The water drive in step 3 ensures consistency in the exsolving of gas and water while the gravity drainage of step 4 separates the water, gas and oil. This leads to a mixed drive reservoir with gas and water perforations.

The secondary stage of the recovery involves the water flooding to maintain the pressure in the reservoir and displace oil with its gas and water components. This stage has gas flooding which compliments water flooding with a focus on the pressure in the gas cap. This secondary level is a human intervention process that works through an advanced mechanism to extract more oil. The enhanced oil recovery (EOR) method goes beyond the conventional methods to incorporate a triple process of thermal, chemical and miscible gas recovery. The thermal method capitalizes on the injection of steam, combustion, microwave and hot water for the most efficient method. The use of the chemical approach for enhanced oil recovery improves the viscosity and permeability. It also reduces alkaline floods between the oil and water properties. In order to extract all the oil from the process, a miscible gas flooding mechanism introduces carbon dioxide, nitrogen and hydrocarbon gases, which penetrate the rocks to force up the rest of the oil. Different approaches that encourage high mobility gases make this process much easier.  Finally, the tertiary process leads to the infill recovery involving a drilling process enhances the oil production through

  • Improved production rates

Impact of Fluid Properties on Field Development Plans

The recovery factor is critical in oil production because of enhanced removal of oil, water and gas through an EOR process. This releases any trapped oil from the surface through reservoir pressure and the estimated ultimate recovery. Exploited and unexploited areas of the Gulf of Mexico use saturated and under saturated pressures in the primary stage to release different bubble points of the oil and expansion rates. At this stage, natural pressure from the reservoir featuring the gas drive, water, gravity and mixed drives raises the oil to the surface level. This gives way to the secondary stage, which displaces the hydrocarbon elements to lead to the EOR for optimized recovery. The progressive techniques ensure that more crude oil comes out of the recovery stages. From the three stages, the EOR accounts for more than 60% of the oil recovery.

Applying temperature, pressure and crude oil in the gas injection is critical for the gas injection stage. The EOR techniques such as the Water-alternating-gas (WAG) contributes to the success at the tertiary stage. Injecting water and gas into the reservoir stimulates the oil production process. However, in order to exploit the gas fields, pressure reduction in the reservoir is more effective. Steam and gas injections facilitate for the extraction of heavy oils while lighter oils come up through the WAG and miscible gas injection. Contemporary techniques include the use of modern technology for greater impact and exceptional recovery (Guo, 2011). This is the improved oil recovery (IOR) for greater RF. Despite these benefits, challenges of the EOR include its high costs and environmental factors as seen in the Gulf of Mexico case (Shepherd, 2009)

  • North Sea oil fields cases

In deep water, reservoirs, natural gas and liquid petroleum combine forming hydrocarbons. The Norwegian Sea represents a high recovery section of more than 60% and this is similar to the Mexican Gulf’s where the exploration of offshore reservoirs is on a large scale (Tang, 2014). An average field would have between 20-40%. Global locations such as Saudi Arabia have as high as 80-90% rates. The Gulf of Mexico has similar depths, high pressure and temperatures drilling needs.

This is different from smaller-scale reservoirs in the North Sea like the Ekofisk oil whose recovery factor is less than 30% (Cordes, et al., 2016). Factors contributing to this low level include complex surface porosity and poor pressure balance between the hydraulic and the reservoir pressure. Drops in the pressure leads to disruption in the bubble point hence a low viscosity caused by rising gas from the oil. When this happens, the oil flows back to the reservoir because it lacks mobility. The introduction of water and gas ensures that the pressure is right for increased production. This implies that the condition of the surface, ability to displace the fluids and improved reservoir volumes and pressure are important (Webb, et al., 2014).

References

Ambrose, R. J. et al., 2012. Shale gas in place calculations. SPE Journal, 17(1), pp. 219-229.

Ceron, F., 2017. Mexico-Oil and Gas. [Online]  Available at: https://www.export.gov/article?id=Mexico-Upstream-Oil-and-Gas [Accessed 19 September 2017].

Demirbas, A., 2011. Competitive liquid biofuels from biomass. Applied Energy, 88(1), pp. 17-28.

Environment Canada, 2017. Isthmus. [Online]  Available at: https://www.etc-cte.ec.gc.ca/databases/Oilproperties/pdf/WEB_Isthmus.pdf [Accessed 2 November 2017].

Ghannam, M. T., Hasan, S. W., Abu-Jdayil, B. & Esmail, N., 2012. Rheological properties of heavy & light crude oil ixtures for improving flowability. Journal of Petrolue Science and engineering, Volume 81, pp. 122-128.

Guo, B., 2011. Petroleum production engineering, a computer-assisted approach. s.l.:Gulf Professional Publishing.

Houston, 2017. BSEE: Gas, condensate release reported in Mexico. Oil & Gas Journal, 19 January.

Jorge, E., Perez, R., Luis, P. P. & Carlos, J., 2014. Corelations to estimate jkey gas condensate properties through field measurement of gas condensate ratio. Amsterdam, SPE Annual Technical Conference and Exhbition,.

Kaplan, G., 2017. US Gulf of Mexico oil production. [Online]  Available at: https://peakoilbarrel.com/us-gulf-of-mexico-may-production/ [Accessed 2017 November 2017].

Kennedy, R. l., Knecht, W. N., Daniel, T. G. & Baler, H., 2012. Comparison and contrasts of shale gas and tight gas developments in North American Expereince and Trends. Saudi Arabia, SPE.

McCain, W. D., Spivey, J. P. & Lenn, C. P., 2011. Petroleum Reservoir Fluid Property. Oklahoma: PennWell.

Rigzone, 2017. Petroskills: How is heavy Oil and how is it formed?. [Online]  Available at: https://www.rigzone.com/training/heavyoil/insight.asp?i_id=184 [Accessed 2 November 2017].

Santos, R. G., Loh, W., Bannwart, A. C. & Trevisan, O. V., 2014. An overview of heavy oil properties and its recovery and transportation methods. Brazilian Journal of Chemical Engineering, 31(3), pp. 571-590.

Shepherd, M., 2009. Factors influencing recovery from oil and gas fields. In: Oil Field Production Geology. s.l.:AAPG Memoir, pp. 37-46.

Webb, K. et al., 2014. Recory rates, enhanced oil recovery and technological limits. Philosophical Transactions A Math Phys Eng Sci, 13 Jan.

Wu, X., Srivastava, P. D. D. & Amirlatifi, A., 2016. Recovery factor prediction for deepwater Gulf of Mexico oilfields by integration of dimensionless numbers with data mining tecniques. Aberdeen, SPE Intelligent Energy International Conference and Exhbition, 6-8.

Zuo, J., Zabel, F., Taylor, S. & Law, D. H.-S., 2010. Impact of uncertainity of heavy oil fluid property measurements. Journal of Canadian Petroleum Technology, 39(3), pp. 28-35.

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