| dc.description.abstract | Reservoir simulation studies are the most detailed analysis that can be performed in order to evaluate future performance and remaining reserves of a reservoir, given the in-place volumes. This holds true both for conventional and unconventional reservoirs. The two numbers, in-place volumes and long term deliverability of the reservoir, need to be ascertained with fair amount of accuracy. This is central idea of this dissertation.
The overall objectives of the dissertation are outlined in the form of two simulation case studies – one conventional and the other unconventional.
For the conventional reservoir, history matching and subsequent forecasting work becomes a challenging task if limited supporting production data is available and the reservoir is severely depleted. For an offshore, volatile–oil reservoir, added to this challenge was an uncertainty in fluid PVT, where the data clearly suggested presence of condensate, but with black oil properties. The permeability distribution from logs was counterintuitive to the production data from the wells. The reservoir had a structural relief in excess of 1000 ft., most likely having API gradient, but both the API and the GOR data indicated that there were possible errors in measurement. There was uncertainty associated with original oil-water contact also. The production data showed the reservoir to follow primarily a classical solution gas-drive response, but simple material balance analysis proved a weak aquifer effect as well.
The approach followed in simulation was the process of elimination. Pressure match was first achieved, but questions remained about its robustness around the main sealing fault. GOR was targeted next and several different condensates and one full compositional fluid model of a nearby reservoir were unsuccessfully tested. For matching the historical gas production, a new high condensate yield fluid PVT was used. The idea of another oil-water contact (OWC) was tested in the saddle of the reservoir to account for most likely early water breakthrough in a well there. The secondary gas cap formation and its effects were crucial in achieving satisfactory history match.
The confidence in the history match, as having captured the physics of the flow, led to forecasting scenarios which were not possible with a black oil model. Most of the data was found not to be erroneous. What was needed was judicious data interpretation to achieve satisfactory history match. To produce these kinds of depleted, faulted reservoirs further, a strategy to better manage the evolution of secondary gas cap was of utmost importance.
For the unconventional reservoirs the challenges are equally daunting. The unconventional liquids-rich “shale” reservoirs are made up of shales, siltstones or carbonates. Depending on fracture connectivity, these reservoirs may or may not produce water from aquifers above/below them. Simulation modeling work to estimate reserves for such reservoirs is often restricted to, a well based stimulated rock volume (SRV). Aquifer effects, at the boundary, are often not taken into consideration as water production is insignificant or in some cases non-existent. The in-place volume may not pose as big a challenge for SRV, but the long term deliverability of the wells is affected by the different boundary conditions, which constitutes the natural drive of these reservoirs. Material balance analysis, used for analyzing production data, cannot be applied here as it is difficult to measure the average reservoir pressure at the well as no tank-like behavior is seen. Decline curve analysis (DCA) and Rate transient analysis (RTA) have limited success for these liquids-rich plays. The former is limited by high shrinkage of volatile oils, which liberate a lot of gas below the bubble point, that might aid or impede long-term well performance. The latter analysis is known to give non-unique solutions under transient conditions.
In order to overcome these limitations a new method is proposed which is based on linear flow regime of these reservoirs. Unlike previous studies where either the matrix alone or the aquifer alone are taken into consideration as source term in the fracture equation, here we take both the matrix and the aquifer as two separate source terms in the fracture equation with two separate interporosity flow parameters, each with slab configuration. The overall performance of the well is dependent on the term, (?/w), called as Dual Porosity Proppant Number. For the reservoir, this is defined as volume weighted, dimensionless surface flux transferred from a unit area of matrix to the fracture, per unit matrix volume. As a big picture, this number determines the amount of successful stimulation achieved within the dual porosity reservoir. Based on flow analysis from two different areas, it is possible to reduce the uncertainty associated with RTA alone. One area estimates the aquifer drive and the other estimates the derivative of dimensionless productivity index against time. This derivative of dimensionless productivity index serves dual purpose. It acts as a pressure variable which gives information about the rate of transient-area generation in the reservoir due to drawdown at the well. Hence conventional RTA can be applied. The other purpose is to help evaluate the long-term well performance since it is part of productivity index. Below the bubble point, the solution gas drive is handled with the help of equivalent Muskat’s method for Volatile oil.
Having established the theoretical basis, we then illustrate the effects of various reservoir drives on future performance of such unconventional reservoir. A synthetic field-wide simulation case shows the application and results, which brings out its significance, with and without the use of this method.
The last chapter covers the performance prediction of a horizontal well with transverse fractures without the assumption of linear flow. No detailed analysis of the work is presented. | en |
