At the present time one of the most common methods of well testing is pressure buildup test at the shut-in of production well. When the well is closed for research the process of bottomhole pressure (BHP) increase is accompanied by a change in the dynamic head and increasing the gas pressure at annular space (Shagiev, 1998). Growth of casing pressure above limit pressure can lead to technical problems at wellhead. This paper describes a method for predict the pressure in the annular space and the dynamic head in the end of the pressure transient test and bottomhole pressure buildup to the current reservoir pressure. Express-method of forecasting of casing pressure is tested on experimental examples of research in mechanized wells. In most cases, calculated casing pressure value corresponds with the measured data (successful prediction by this method is 70%). In most cases, forecasting method of casing pressure recovery for vertical mechanized wells allows to determine the possible excess casing pressure above the critical pressure at the wellhead (for example, a possible increase above of test pressure and limit pressure which can connect with some gaps at the wellhead) pressure buildup test. Presented express-method of forecasting can be used in the selection of wells-candidate for well testing, at prevention and reduction of potential problems and for discontinuation well testing due to high casing pressure, improving the success of well testing.
The experience of working with extra-heavy oil producing wells profitably requires the use of available technologies to the limits of their capabilities. Due to its heavy use of electricity, the Electrical Submersible Pump (ESP) has often proven unsuitable for fields producing high-viscosity fluids. However, in some cases, given the conditions downhole and fluid behavior, along with technological changes, it has been possible to use ESPs at moderate cost.
Exploitation today has become technically and economically feasible for reservoirs in upper or lower layers that were previously uneconomical given lifting, transportation and marketing costs.
Previously discovered resevoirs in the Llanos Basin of Colombia were considered of no commercial value given the characteristics of its oil (higher viscosities to 1,000 cps at 60° F / 14.7 psia and API gravities less than 10°). The Operating Companies of the same blocks discovered other, more easily exploited oil reservoir units. These oilfields, now in their mature stages, have high production costs because of the inevitable increase in water cut and/or decreased pressure. This has spurred to the use of existing infrastructure and advances in technology for lifting, processing and transportation of heavy and extra-heavy oil reservoir units already discovered.
There have been several challenges in developing extra-heavy oil wells, such as organic precipitation, presence of scales, strong emulsions and high GOR.
ESP technology has advanced in the extraction of large fluid volumes, smaller stage diameters, metallurgy resistant to corrosion and abrasive solids, stronger shafts, and conditions of high pressure and high temperature. However, there are very few developments in sustainable extraction of heavy oil and extra-heavy oil.
This article describes an example of implementing the Electro Submersible Pump as a feasible method for artificial lift in wells producing extra-heavy oil.
The Chichimene field produced by Sucker Rod Pumping of Guadalupe intervals (K1/K2) to achieve a production of 5000 BOPD with approximately 20 wells. Subsequently, the decline in production of such formation, associated with high water cuts allowed the implementation Electro Submersible Pump in most wells, including producing wells San Fernando formation (T2). Due to increasing oil prices and market demand for Heavy Oil campaign began development of reserves in this formation. This paper presents the learning curve in implementing Electro Submersible Pump as a method for artificial lift extra heavy oil wells and pumping the subsequent transition to PCP.