Heavy Oil Wells Research Articles

Calculating the Steam-Stimulated Performance of Gas-Lifted and Flowing Heavy-Oil Wells

Calculating the Steam-Stimulated Performance of Gas-Lifted and Performance of Gas-Lifted and Flowing Heavy-Oil Wells Here is a method for combining reservoir and wellbore pressure-drop calculations to predict the performance of steam-stimulated wells producing by natural flow or by gas lift. The extent to which such process variables as treatment size, lift-gas rate, wellhead pressure, and prestimulation rate affect performance can be calculated with this method. Introduction When fluids are produced from the reservoir in which they are found and transported to separation or treating facilities on the surface, three basic types of multiphase fluid flow are encountered: Flow to the wellbore through the porousmedium, Vertical flow in the wellbore from thesandface to the wellhead, and Horizontal flow through flowlines from thewellhead to the surface facilities. The first two types of flow are coupled by the flowing bottom-hole pressure at the sand-face; the latter two types are coupled by the flowing wellhead pressure. A complete description of such a system requires simultaneous solution of the three flow problems. A method for simultaneously solving the reservoir and wellbore flow problems has been developed for use in calculating the steam-stimulated performance of a well that is either flowing or being produced by continuous gas lift. For simplification, it has been assumed that the wellhead pressure can be specified. This implies that the flowline is short or is adequately sized to have only a minor pressure drop. This is not always the case in practice, and it may sometimes be desirable to incorporate a flowline pressure drop calculation. pressure drop calculation. It is important that the wellbore and reservoir flow problems be considered in combination for the problems be considered in combination for the following reason. For a given wellhead pressure, the flowing bottom-hole pressure - and hence production rate - is controlled by the pressure drop that occurs in the wellbore. This pressure drop is a function of the oil, water, and gas flow rates and fluid properties, some of which are strongly temperature properties, some of which are strongly temperature dependent. The problem is compounded in steam-stimulated wells because both the flow rates and the temperature change significantly during the production cycle. For a well producing viscous oil, the production cycle. For a well producing viscous oil, the change in temperature is particularly important because of its effect on oil viscosity. A temperature change of only 60 deg. F in the tubing string can often result in a difference of several hundred psi in the flowing bottom-hole pressure, with a consequent effect on production rate. Under some conditions, variations in pressure drops in surface flowlines can also be significant and must be considered because of their influence on wellhead pressure. The paper describes how two previously published techniques were combined to solve the stated problem, illustrates the combined method by example problem, illustrates the combined method by example calculation, and establishes the validity of the method by comparing calculated and field results. Also, the method is used to calculate the extent to which several important process variables, such as treatment size, lift-gas rate, wellhead pressure, and prestimulated production rate, affect stimulated performance. prestimulated production rate, affect stimulated performance. JPT P. 1207

Early Results of the First Large-Scale Steam Soak Project in the Tia Juana Field, Western Venezuela

Well inflow performance and production mechanisms are discussed for a 74-well steam soak project in a reservoir containing 10 to 14 deg. API oil On the basis of the results obtained so far, a significant increase in ultimate recovery is expected for injection of relatively small amounts of steam. Introduction In view of their size and favorable characteristics, Shell's heavy-oil fields on the eastern coast of Lake Maracaibo, Venezuela-known as the "Bolivar Coast" - are obvious candidates for the application of thermal recovery methods. During the last decade various methods have been tested, such as steam drive, steam soak and in-situ combustion. Steam soak was discovered as a promising production method rather accidentally in 1969, during early steam drive testing in the Mene Grande Tar Sands. When steam erupted at the surface due to breakdown of the overburden, the injection wells were backflowed to relieve the reservoir pressure. This resulted in high oil production rates, all the more impressive because the reservoir is unproducible by primary means. It was concluded that injection of limited amounts of steam might be a very effective method for stimulation of heavy-oil wells. To obtain information that would be more widely applicable, testing of the process was continued in the eastern part of the Tia Juana field (Fig. 1). Here even more favorable results were obtained in Mene Grande. This created sufficient confidence to prompt a large-scale project, which was considered essential for an adequate evaluation of ultimate recovery, steam requirements, mechanical problems and economic prospects. To obtain an early answer on the ultimate recovery a fairly depleted area was selected in the western part of the same field ("A" in Fig. 1). The first steam was injected in March, 1964. This paper describes the performance until the end of 1966. The production mechanism and well inflow performance are discussed in some detail. In view of the favorable results obtained so far, steam soak operations have expanded considerably since the start of this project. Presently, five other projects are under way, of which two are about the same size as the one under discussion, with further extensions being programmed. Description of the Project Reservoir Data Shell's part of the Main Tia Juana reservoir has a proven area of 8,800 acres and an average net oil sand thickness of 130 ft, It contained an initial quantity of 2,750 million bbl of stock tank oil (STOIIP), with an API gravity ranging from 10 to 15 deg. API and a viscosity of 100 to 10,000 cp (at 122F). As a geological unit it is known locally as the Lower Lagunillas member of the Lagunillas formation, which is early Miocene in age. The sand bodies are believed to be distributary channel sands deposited in a lower coastal plain. Most of the channel sands have lateral and some vertical communication. The field was developed mainly in the period from 1936 to 1950. The ultimate primary recovery is estimated at 18.1 percent of STOIIP, of which 12.5 percent STOIIP had been produced by the end of 1963 from some 540 wells. JPT P. 101ˆ