Analysis and Evaluation of Alternative Concepts in Modeling Tarmats To Conform to Laboratory Investigations and Field Conditions
- B. Tripathy (Arabian American Oil Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1988
- Document Type
- Journal Paper
- 1,109 - 1,113
- 1988. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 5.4.6 Thermal Methods, 4.3.3 Aspaltenes, 5.1.1 Exploration, Development, Structural Geology, 4.3.4 Scale, 5.5 Reservoir Simulation, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment, 5.2 Reservoir Fluid Dynamics, 5.1.2 Faults and Fracture Characterisation
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Black-oil reservoir simulators are universally formulated to handle a maximum of three different fluid phases - i.e., oil, water, and gas. The phase identity of tar, occurring in concentrations called "tarmats" within or marginal to petroleum reservoirs, varies widely from highly viscous hydrocarbon fluid to near-solid material. In black-oil modeling of tarmat reservoirs, therefore, considerable challenge is posed in characterizing tar as a drastic departure from the three fluid phases. No published literature provides concentrated details on tarmat modeling with an emphasis on comparative analysis and adaptability of different state-of-the-art modeling techniques. This paper compares the two approaches adopted most often to characterize tar in a model - i.e., as a highly viscous hydrocarbon fluid and as a relatively impermeable rock matrix. Other less commonly used methods that also may be reasonable are not discussed.
Tar or bitumen often occurs within or marginal to petroleum reservoirs. Their origins are well documented in the literature.1-3 Rogers et al.4 characterized four different types of subsurface tar on the basis of level of concentration, continuity, and structural position relative to the oil/water contact (OWC): (1) disseminated tar in gas reservoirs, (2) disseminated tar in reservoirs containing high-gravity oil, (3) tar concentrations near the OWC levels, and (4) tar concentrations updip in the oil column.
Of the four different categories of subsurface occurrences, tar deposits at the OWC have a significant effect on oil and gas production. Such deposits with uniform or varying levels of thickness are commonly known as tarmats. As a continuous body, they often stay fully submerged or extend into the oil column and pose adverse effects on natural waterdrive by restricting the movement of potential influx water into the oil zone. Accurate identity of tarmats in a reservoir model is therefore vital to study the behavior of these types of reservoirs. Tarmat modeling in this paper is restricted to tar concentrations near the OWC levels, as opposed to disseminated tar occurring elsewhere in a reservoir.
Approaches to Tarmat Modeling
A typical tarmat, as might exist in a reservoir, is exhibited in a sectional view in Fig. 1. The straightforward approach to represent it in a black-oil model is to obtain a rigorous characterization of its existence, as may be allowed under "beta" formulation. This is obtained by simulating the tarmat as a highly viscous oil zone. The second approach constitutes a linear approximation to the characteristic representation of mass transfer from the aquifer through the tar barrier. This can be explained by assuming that the cumulative rate influx through the tarmat is a result of (1) a matrix porosity link of the tar zone - an initial characteristic - or (2) a fracture porosity link of the tar zone - a developed characteristic, as in the case of tarmat breakdown.
In terms of the fluid-flow equations for a tar block, the two phenomena sequentially correspond to Eqs. 1 and 2.
Equation 1, 2 and 3
The mass storage term f(f, Sw, t) has been neglected in Eq. 2 because the fractures typically exhibit small storage capacity.
In field observations where the tar saturation often exceeds a value of 20%, as in the case of most tarmats, the matrix porosity link is small. The total influx into the reservoir, therefore, is given by Eq. 2.
Eq. 3, where qw is the total water influx rate, constitutes the approximate representation of water migration through the tar zone when it is modeled as a part of a reservoir fluid system, whereas Eq. 2 represents water movement when the tarmat is modeled as a part of the aquifer rock matrix.
Fracture porosity link resulting from tarmat breakdown is ordinarily a time-delayed process. Common black-oil simulators are incapable of handling fracture flow together with matrix porosity link. As will be explained later on, fluid transfer in a leaked tarmat is approximated through the use of relative permeability curves, where the fracture permeability is allowed to increase with an increase in saturation. For a tar viscosity of more than 100 cp [100 mPa·s], tar-zone displacement is a near impossibility and the fracture link is the main cause of aquifer support. However, with assignment of a capillary transition zone to the tar-containing rock matrix, a matrix porosity link is established in the model whose existence in the field is extremely doubtful.
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