Euclides J. Bonet

Evaluation of Permeability Changes in a Carbonate Rock under Carbonate Water Flow

Carbon dioxide (CO2) injection in reservoirs promotes reactions which depend on rock nature, brine composition, partial pressure of CO2, reservoir temperature and pressure among other conditions. The reactions may cause changes in the petrophysics properties, including porosity and permeability, that are important parameters to the fluid flow. The present study focus on the effects of carbonated brine injection in carbonate rocks similar to pre salt reservoirs. The effects are evaluated through the changes of the rock absolute permeability provoked by the acidic action of the injected fluid. Experiments were designed to detail permeability changes along the length of a long carbonate core using using a coreholder equipped with multiple pressure taps. The experiments were conducted in dynamic regime, at the temperature of 22°C and at the mean pressure of 2,000 psi, at flow rates of 0.5; 1 and 2 cc/min. The results show significant permeability alterations at the different segments of the sample, which are also highly dependent on the injection rate.

Water Injection In Viscous Oil Through Horizontal Well

Water injection is often used as a recovery method for light oil reservoirs; however, for heavy oil reservoirs its efficiency is not so high mainly due to the unfavorable water-oil mobility ratio. For this reason, well placement is an important step of the production strategy definition because it can guarantee the economic viability of heavy-oil, deep water fields. This work aimed to analyze the behavior of heavy oil displacement by water injection, through both experimental and numerical simulation studies. A rectangular plate filled with porous media was used; its petrophysical characteristics were determined, as well as the relative permeability and capillary pressure. Two horizontal wells were used and the laboratory test was performed in two stages: first, an oil saturation phase and then a displacement phase. Water saturation maps were generated for the two stages, in order to better analyze distortions due to friction effects in the horizontal wells. A numerical simulation model was built to reproduce the behavior observed in the experiment and compare the friction pressure drop effects. It was further used as the basis of a hypothetical reservoir prototype, in field scale; the results from the simulations reproduced the experiment data qualitatively, however, some differences were observed. The friction pressure drop in the wellbore did not seem to affect the flow, especially according to the simulation results. Introduction With more frequent use of horizontal wells and new offshore oil discoveries of viscous oil, it is important to correctly describe the behaviour of viscous oil displacement in porous media. This work aimed to study such behavior through a methodology that involved an experimental displacement test by injecting water in viscous oil through horizontal wells, and the characterization of a porous media. The fluids and porous media characterization are presented in a correlated work. Since this work involves very unfavourable mobility ratio, the initial discussion will focus on the conditions for displacement stability taking into consideration the high oil viscosity. Scale transformation from a model to a prototype was studied and the results for the prototype were calculated by scale transformation and by numerical simulation. The pressure, production and saturation distributions were simulated for the model and compared to the laboratory measurements. Porous Media. The porous media is an Eolian sandstone from Botucatu formation obtained from an outcrop in Ribeirão Claro, PR, Brazil. It was preliminarily cut in a parallelepiped form (88cm x 33cm x 3.2cm), with 24% porosity and 587 mD absolute permeability. The capillary pressure and the water oil stable relative permeabilities can be seen in Table 1, where the normalised water saturation presented is defined by Eq. (1): or wi wi w w S S S S S − − − = 1 * .....................................(1) Oil Displacement Test Experimental and Simulation Model Results. The plate was saturated with water under vacuum. The initial water saturation was obtained by injecting the 212 cP viscous oil laterally in linear displacement geometry; the oil injection rate was 0.15 cm/min. Figure 1 shows a picture of the encapsulated rock plate used in the experiments and the laboratory apparatus. The operating pressure had to be kept to low values due to the large superficial area of the model, otherwise the plate containing the porous media could be damaged. This phase of the experiment provided the irreducible water saturation (Swi) for Eq. (1). Stability Criteria Different authors have studied stability criteria for the flow of water displacing oil. However, since this is not a settled subject, the findings of two authors will be presented here. 2 SPE/PS-CIM/CHOA 97740 Chuoke defined as necessary and sufficient conditions: 1 0 ≥ M .........................................................(2)

Gravity Drainage-Lab Tests, Relative Permeability Calculation, and Field Simulation

In order to confirm the expected high recoveries obtained in gravity drainage field operations we performed a series of lab tests, developed an oil relative permeability calculation, and used this data to conduct a reservoir simulation for a Brazilian offshore oil field. The lab tests were conducted at ambient temperature and low pressure, and were performed in long cores (90 - 252 cm long) with dead oil and conventional production where the oil was produced at the lower end of the vertically oriented core and air entered the upper end. For one test we performed a counter-current drainage test using live oil where the production was collected at the lower end of the core and the liberated dissolved gas was removed counter-currently from the upper end. The saturation evolution inside the core was monitored by an X-Ray system. Using the same rock and fluids, centrifuge tests were performed using 3 - 4 cm long plugs to compare to the core displacement test results. When the results did not agree, an explanation for the variance using a model of bundles of capillary tubes was postulated. Verification using the principle of minimum energy was performed. A computer program was implemented to calculate the oil relative permeability using the lab data, the results of which were compared with the published literature. The calculated relative permeability was used to simulate the behaviour of a Brazilian offshore oil field that was initially exploited with water injection, and then, due to the appearance of a secondary gas cap, subsequently subjected to gas injection into the crest of the structure.