Reservoir performance

All the parameters discussed above are needed to calculate the volume of hydrocarbons in the reservoir. The formation permeability is a measure of the ease with which fluids can pass through the reservoir, and hence is needed for estimating well productivity, reservoir performance and hydrocarbon recovery. 

The relationship between the tubing performance and reservoir performance is more fully explained in Section 9.5. 

Step 8. Go to Step 3 if you have made any changes to the model. Otherwise proceed with the study to predict future reservoir performance, etc. 

The size of the main oil and gas separators is of primary initial sizing concern when this contingency is discussed. A normal 13% rate contingency is added to size the main oil-gas separator they are not easily added if a mistake is made on reservoir performance. 

The task was to develop a facility-operating plan that provided optimal producing capability with no facility constraints in meeting specific reservoir withdrawal targets. Facility modifications and major investment timing were to be optimized while observing reservoir performance under unit operations. 

Additional fluid-lift capability was planned through a combination of increased gas-lift capacity and installation of submersible pumps. Gas-lift system expansion was critical for future flexibility of the system to allow target production rate modifications on the basis of reservoir performance. Most field gaslift compressors used to supplement plant compression were to be shut in as soon as gas-lift system expansions were completed. 

With the need to monitor reservoir performance closely and the ongoing requirement to change production targets, a computerized data system is beneficial for reservoir surveillance. Automation provides more frequent well test data to assist in developing well work programs and artificial lift improvements. 

The tests cannot be extrapolated directly to field reservoir performance because the spatial geometry is different. The core tests have a linear, 1-dimensional flow geometry while the actual reservoir has radial, 3-dimensional flow. In 3-dimensional flow the displacement efficiency is typically less than that measured in linear displacement studies. Chilton (1987) showed in his computer simulation studies that, as compared with the linear flow case, the predicted oil produced was 10% less for the two-dimensional model and 27% less for the three-dimensional model. However, when mobility control was used with a tenfold decrease in carbon dioxide mobility, the calculated improvement in displacement efficiency was much less for the linear case than the three-dimensional case. This result indicates that the increase in displacement efficiency under field conditions should be greater than that recorded in these linear laboratory tests. 

Heffer, K.J., Last, N.C., Koutsabeloulis, N.C., Chan, H.C.M., Gutierrez, M. and Makurat, A. 1994. The influence of natural fractures, faults and earth stresses on reservoir performance - geomechanical analysis by numerical modelling. In North Sea Oil and Gas Reservoirs - 111, pp. 201-211. 

Fracturing and fault compartmentalization of sandstones fundamentally affects reservoir properties and may significantly influence the fluid migration pathways in a basin (Knipe, 1993). Open fractures may form high-permeability conduits, whereas cement-sealed fractures form barriers to fluid flow. Seismic, petrophysical and reservoir performance data allow regional (field-scale) effects of faulting on fluid flow to be constrained. However, much fracturing and associated cementation may occur at sub-... 

The accurate modelling of reservoir performance in siliciclastic systems requires an understanding of structural and diagenetic permeability heterogene-... 

Simon, R., and F.J. Kelsey. 1971. The use of capillary tube networks in reservoir performance studies ... 

With particular respect to assessments of reservoir continuity, it is critically important to determine the degree to which reservoir fluids have attained compositional equilibrium (Larter Aplin 1995 Wavrek et al. 2001). In order to be able to identify the presence of discontinuities that may influence reservoir performance one must be able to discriminate between ephemeral geochemical variations and those related to the presence of flow barriers. 

Jing, Zh., Watanabe, K., Willis-Richards, J. Hashida, T. 2002. A 3-D water/rock chemical interaction model for predicting of HDR/HWR geothermal Reservoir performance. Geothermics 31 pp.1-28. 

The only data used were those obtained from effective steam soaks of type I reservoirs performed under conditions conforming to requirements. The results of the study are given in Fig. 24 and 25. 

By applying the dimension reduction procedure indicated above we are able to limit the number of states to a manageable size. At the system level we then obtain the steady state probabilities and hence system regularity by standard Markov methods. The model has been applied in relation to oil production where reservoir characteristics have to be included in the model. For example for a gas injection system a degraded performance (e.g., 66.67% injection capacity) may have no immediate effect on oil production. This is due to the fact that produced gas is sent to flare for a shorter period of time without affecting the reservoir performance. Due to environmental restriction imlimited flaring is not acceptable, hence after a period of some hours production has to be reduced... 

Even when history matching technique is used to estimate the description data of petroleum reservoirs, the accuracy of the parameter estimates is not guaranteed. There are a number of sources of error in history matching, the major ones being the mathematical model, observability, the criterion function and the match period (2,8). It is, therefore, important to determine the reliability of estimated description data as well as the reliability of both the history and the predicted reservoir performance data. 

While, for the past decade, all the attempts to economically move the North Slope gas to markets have failed, the gas is currently being reinjected in the Prudhoe Bay Field. What did that gas reinjection do The 1976 study of Prudhoe Bay Field (State of Alaska Report 1976) shows that with sale of gas and crude oil production rate of 1.5 million B/D, the daily oil production rate would start to decline after recovery of 4.75 billion barrels in 1985 and without sale of gas it would start to decline after recovery of 5.75 billion barrels in 1987. So far 7.1 billion barrels of crude oil have been produced from Prudhoe Bay Field. The current Prudhoe Bay oil production rate is 1.5 million B/D. The recent predictions based on actual reservoir performance and history matching indicates that the possibility of producing 7.6 billion barrels of crude by end of the year 1991. Comparing the value of gas to oil, clearly the reinjected gas has served the best purpose. 

Ahmed, T. 2010. Reservoir Engineering Elandbook, 4th ed. Boston Gulf Professional Publishers. This book explains the fundamentals of reservoir engineering and their practical applications in conducting a comprehensive field study (from Preface, p. xv). Divided into 17 chapters., the coverage includes reservoir fluid behavior and properties, fundamentals of reservoir fluid flow, oil and gas well performance, oil recovery mechanisms, and methods for the prediction of oil reservoir performance. 

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