This paper deals with hydraulic fracture treatment issues encountered in the Priobskoye field. The focus is the determination of fracture parameters and their variation with time.

As always there are two key parameters that control the treatment effectiveness: fracture length and fracture conductivity. It is well known that, often, the actual fracture parameters are never as good as those for which the fracture is supposed to be designed for. Different reasons have been advanced in the past to explain this disparity, such as failure to fill the fracture with proppant up to the top; inefficient proppant transport into the fracture; proppant settlement by gravity; porous pack damaged with fracturing fluid gel residue. In addition, the apparent fracture parameters may be affected by multiphase flow; non-Darcy flow; and various combinations of the above causes. Isolating the individual impact may never be possible. Despite the many approaches to describe the process of fracture design and the subsequent fluid flow in the fracture, the actual post-treatment effectiveness has not been resolved yet.

The frac job analysis remains so far an urgent issue which puts a variety of challenges to the scientific community and petroleum engineers. Understanding all the phenomena that take place in the wellbore and in the reservoir during both the fracture job and the subsequent well production would allow the selection and design of appropriate fracture parameters for an economically sound field development plan.


Before fracturing the first task is the selection of well candidates. At this stage the optimal fracture parameters are chosen and the well postfracture productivity is predicted. The evaluation at this stage is based on well logging data and general reservoir data. Then a minifrac is done, which is a fracture calibration treatment to refine the fracture propagation model. The fracture propagation model provides the final expected fracture parameters. The fracture length and height[1] are then computed after the frac job is over; they are derived from the pressure profile and fluid injection profiles. Most often the results are considered correct and further efforts are curtailed.

Presented below are the results of a study aimed at reviewing the difference between the fracture parameters derived from pressure analysis during the treatment and those derived from the well performance analysis. The analysis is based on typical transient-pressure decline-curve analysis. We also give an explanation for the observed difference. No less interesting is to know which parameter is prone to greater error in its estimate.

Brief description of the Priobskoye field

The Priobskoye field was discovered in 1982 and is unique in terms of its reserves. The commercially productive reservoirs AS10–1, AS10–2, AS11–2 exhibit a very complex discontinuous lenticular clinoform structure within the confines of the South License Area (SLA). The reservoir permeabilities of the productive intervals are low, estimated to be 1 to 3 md; oil saturation is at 50 to 56%; porosity at 18%; average depth at 2488 to 2586m.

Reservoir AS10–2, being rather thin and small, is not considered as a distinct target but a part of reservoir AS11–2. Thus, reservoirs AS10–1 and AS11–2 are the major productive reservoirs; they cover large areas of 59 and 188 thousand hectares, respectively, and have average pay thicknesses of 4.3 and 8.3 m. Their oil reserves are classified as marginal and costly stimulation technologies are required to produce this oil.

Because of the reason we will mention below we are mostly interested in the northeastern part of the Priobskoye field where only AS11–2 is present. Table 1 shows the averaged values of the chemical and physical properties of the formation fluid collected during PVT downhole sampling. As can be seen from the table, oil is undersaturated; and with moderate viscosity; the bubble point pressure is much lower that the reservoir pressure. Surface oils are sour (1.10 to 1.22% sulphur) and waxy (2,46 - 2,57% paraffins).

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