The essentials of reservoir simulation...
Reservoir Simulation To run a reservoir simulation model, you must: (a) Gather and input the fluid and rock (reservoir description) data; the model incorporates data on the reservoir fluids (PVT) and the reservoir description (porosities, permeabilities etc.) and their distribution in space. (b) Choose certain numerical features of the grid (number of grid blocks, time step sizes etc); (c) Set up the correct field well controls (injection rates, bottom hole pressure constraints etc.); it is these which drive the model; (d) Choose which output (from a vast range of possibilities) you would like to have printed to file which you can then plot later or in some cases - while the simulation is still running. The output can include the following (non-exhaustive) list of quantities: • The average field pressure as a function of time • The total field cumulative oil, water and gas production profiles with time • The total field daily (weekly, monthly, annual) production rates of each phase: oil, water and gas • The individual well pressures (bottom hole or, through lift curves, wellhead) over time • The individual well cumulative and daily flowrates of oil, water and gas with time • Either full field or individual well watercuts, GORs, O/W ratios with time
• The spatial distribution of oil, water and gas saturations throughout the reservoir as functions of time i.e. So(x,y,z;t), Sw(x,y,z;t) and Sg(x,y,z;t) The central objective of reservoir simulation is to produce future predictions (the output quantities listed above) that will allow us to optimise reservoir performance. At the grander scale, what is meant by “optimise reservoir performance” is to develop the reservoir in the manner that brings the maximum economic benefit to the company
Appraisal stage: at this stage, reservoir simulation will be a tool that can be used to design the overall field development plan in terms of the following issues: • The nature of the reservoir recovery plan e.g. natural depletion, waterflooding, gas injection etc. • The nature of the facility required to develop the field e.g. a platform, a subsea development tied back to an existing platform or a Floating Production System (for an offshore fileld). • The nature and capacities of plant sub-facilities such as compressors for injection, oil/water/gas separation capability. • The number, locations and types of well (vertical, slanted or horizontal) to be drilled in the field. • The sequencing of the well drilling program and the topside facilites.
It is during the initial appraisal stage that many of the biggest i.e. most expensive- investment decisions are made e.g. the type of platform and facilities etc. Therefore, it is the most helpful time to have accurate forward predictions of the reservoir
performance. But, it is at this time when we have the least amount of data and, of course, very little or no field performance history (there may be some extended production well tests). In such cases, we may still be able to build a range of possible reservoir models, or reservoir scenarios, that incorporate the major uncertainties in terms of reservoir size (STOIIP), main fault blocks, strength of aquifer, reservoir connectivity, etc. By running forward predictions on this range of cases, we can generate a spread of predicted future field performance cases For example, scenarios for various cases may involve: • Different assumptions about the original oil in place (STOIIP; Stock Tank Oil Originally In Place). • Different values of the reservoir parameters such as permeability, porosity, net-to-gross ratio, the effect of an aquifer, etc.. • Major changes in the structural geology or sedimentology of the reservoir e.g. sealing vs. “leaky” faults in the system, the presence/absence of major fluvial channels, the distribution of shales in the reservoir etc..
Mature field development: has been in production for some time (2 - 20+ years) but there is still a reasonably long lifespan ahead for the field, say; 3 - 10+years. At this stage, reservoir simulation is a tool for reservoir management which allows the reservoir engineer to plan and evaluate future development options for the reservoir. This is a process that can be done on a continually updated basis. The main difference between this stage and appraisal is that the engineer now has some field production history, such as pressures, cumulative oil, watercuts and GORs
(both field-wide and for individual wells), in addition to having some idea of which wells are in communication and possibly some production logs. The initial reservoir simulation model for the field has probably been found to be “wrong”, in that it fails in some aspects of its predictions of reservoir performance e.g. it failed to predict water breakthough in our waterflood (usually, although not always, injected water arrives at oil producers before it is expected). At this development stage, typical reservoir simulation activities are as follows: • Carrying out a history match of the (now available) field production history in order to obtain a better tuned reservoir model to use for future field performance prediction • Using the history match to re-visit the field development strategy in terms of changing the development plan e.g. infill drilling, adding extra injection water capability, changing to gas injection or some other IOR scheme etc. • Deciding between smaller project options such as drilling an attic horizontal well vs. working over 2 or 3 existing vertical/slanted wells • It may be necessary to review the equity stake of various partner companies in the field after some period of production although this typically involves a complete review of the engineering, geological and petrophysical data prior to a new simulation study • The reservoir recovery mechanisms can be reviewed using a carefully history matched simulation model e.g. if we find that, to match the history, we must reduce the vertical flows (by lowering the vertical transmissibility), we may wish to determine the importance of gravity in the reservoir recovery mechanism: “educational value of simulation models” and it is a part of good
reservoir management that the engineer has a good grasp of the important reservoir physics of their asset.
Late field development: we define this stage of field development as the closing few years of field production before abandonment. A question arises here as to whether the field is of sufficient economic importance to merit a simulation study at this stage. However, there are two reasons why we may want to launch a simulation study late in a fieldʼs lifetime. Firstly, we may think that, although it is in far decline, we can develop a new development strategy that will give the field “a new lease of life” and keep it going economically for a few more years. For example, we may apply a novel cheap drilling technology, or a program of successful well stimulation (to remove production impairment such as mineral scale) or we may wish to try an economic Improved Oil Recovery (IOR) technique. Secondly, the cost of field abandonment may be so high - e.g. we may have to remove an offshore structure - that almost anything we do to extend field life and avoid this expense will be “economic”. This may justify a late life simulation study. However, there are no general rules here since it depends on the local technical and economic factors which course of action a company will follow. In some countries there may be legislation (or regulations) that require that an oil company produces reservoir simulation calculations as part of their ongoing reservoir management. (A “5-spot” is a particular example of a “pattern flood” which is appropriate mainly for onshore reservoirs where many wells can be drilled with relatively close spacing) The structure of the simulation study work flow: Accurate reservoir description - Develop the simulation model (perform the history match - see below - use model for future predictions -
evaluate alternative operating plans). A history match is when we adjust the parameters in the simulation model to make the simulated production history agree with the actual field performance Pressure transient work - again gives important ancillary information on the reservoir; determine whether there was (i) directional permeability effects, directional fracturing or channelling; (ii) the degree of stratification in the reservoir; (iii) evaluation of the pay continuity between the injectors and producers
A list of possible sources of uncertainty is as follows: • Lack of knowledge or wide inaccuracies in the size of the reservoir; its areal extent, thickness and net-to-gross ratios • Lack of knowledge about the reservoir architecture i.e. its geological structure in terms of sandbodies, shales, faults, etc. • Uncertainties in the actual numerical values of the porosities (φ) and permeabilities (k) in the inter-well regions (which make up the vast majority of the reservoir volume) • Inaccuracy in the fluid properties such as viscosity of the oil (μo), formation volume factors (Bo, Bw, Bg), phase behaviour etc., or doubts about the representativity of these properties • Lack of data - or very uncertain data- on the multiphase fluid/rock properties, particularly relative permeability and capillary pressure, and on knowledge as to how these curves vary from rock type within the reservoir volume away from the wells • Because the representational reservoir simulations model may be poor, e.g. the numerical errors due to the coarse grid block
model may significantly affect the answer in either an optimistic or pessimistic manner. The above list of uncertainties for a given reservoir, especially at the appraisal stage, is really quite realistic