Vertical Steam Research Articles

Pikes Peak Project: Successful Without Horizontal Wells

Abstract The Pikes Peak Steam Project was initiated in 1981 using vertical wells on one hectare spacing. Emphasis later shifted to directional drilling, but no horizontal wells have been used. Wells are initially steam stimulated, but are drilled in three hectare inverted seven-spot patterns and eventually converted to steam drive. Performance at Pikes Peak has remained excellent since inception, with typical early cycle SORs ranging from one to three and recoveries of up to 40% OOIP before drive conversion. Project cumulative recovery is estimated to be over 50% and rising, as third quarter 1995 project performance was 1,330 m3 oil/day from 117 wells. Advantages at Pikes Peak of vertical or directional well development over horizontal well development are proposed and discussed. A vertical well steam stimulation process for bottom water areas is identified and evaluated. Introduction Horizontal wells have rejuvenated interest in selected Western Canadian heavy oil reservoirs using cold production(1–9), steam Injection(10–22), and fireflood technology(23–25). Some of these projects have been highly successful, and there is now a perception among some oil industry upper management teams that a project is not using the best technology unless it employs horizontal wells. Overlooked in this reasoning is evidence that selected projects have exhibited excellent performance using only vertical and directional wells. In the interest of brevity, this paper concentrates on one project and one technology, the Pikes Peak steam project. Emphasis is placed on discussing why vertical and directional well development likely aided project performance. Detailed discussions of other aspects of Pikes Peak project performance are available in the literature(26–29). Project Location and History The Pikes Peak project is located in Township 50, Range 23 and 24 W3M, approximately 65 km east of the town of Lloydminster (Figure 1). The discovery well was drilled in 1970. Primary production was attempted from 1977 to 1980 using reciprocating pumps, but frequent sanding problems occurred and steam stimulation was selected as an alternate exploitation process. Initial tests in 1981 with portable generators, showed sufficient promise for installation of permanent generators and addition of more wells. Higher quality steam slugs yielded very good responses, and systematic expansion was initiated. Directional drilling was incorporated in 1983 to lessen surface impact and reduce costs. Integral project development strategies included selectively drilling inside the oil/water contact and development of effective strategies for conversion from steam stimulation to follow-up steam drive. Geology and Reservoir Description The reservoir contains a viscous crude oil with a gravity of 0.99 g/cm3 and a gas-free viscosity of 25,000 mPa.s at reservoir temperature (18 °C). Van Hulten(30) concluded deposition of the Pikes Peak channel facies was contemporaneous with that of the regional Waseca sands, and channel- sand thickness variations were the result of migrating point bars. A local structural high allows the project area to be free of bottom water. The Waseca channel at Pikes Peak has been divided into a well-sorted, unconsolidated, predominantly quartz, highly permeable (5 to 10 darcies), homogeneous lower unit and a sand/shale interbedded upper unit.

Effects Of Reservoir Heterogeneities On Heavy Oil Recovery By Steam-Assisted Gravity Drainage

Abstract Previous studies of the SAGD process have been based on homogeneous reservoir models. In this paper, new experiments are described which simulate heterogeneous reservoirs. These include reservoirs with thin sha1e layers and reservoirs containing horizontal layers of different permeabilities. The results show that a short horizontal barrier does not affect the general performance greatly. A long horizontal barrier decreases the production rate but, in some configurations, not nearly as much as might be expected. It is observed that faster production is found when a higher permeability layer is above a lower permeability layer than when the conditions are reversed. Introduction The production of heavy oils by gravity drainage to a horizontal well with the continuous injection of steam above follows from the existing steam stimulation and steam flooding practices. The process has been recognized as steam-assisted gravity drainage (SAGD). Rapid development in this area is being encouraged by improved horizontal well drilling technology which allows more favourable economics. Butler et al.(2,3,4) carried out early experimental and theoretical studies on this area. Their theoretical predictions agreed well with the homogeneous reservoir model experiments. No reservoir is completely homogeneous, and the degrees of heterogeneity can vary significantly, even within the same field. It is necessary that preliminary experiments be performed to study the effects of reservoir heterogeneities. The research work presented here is limited to two types of reservoirs which are considered to be representative and close to the real field conditions:reservoirs with thin shale layers,reservoirs containing horizontal layers of different permeabilities. Laboratory studies were conducted using a visual reservoir model saturated with Cold Lake bitumen. The steam injection pressure employed was 153 kPa. Two different well configurations have been investigated.. The first consisted of a vertical circulation steam injector which was perforated near the top of the formation with bitumen produced at the bottom; the second employed a similar configuration to the first, bur with steam introduced slightly above the production well at the base of the formation. Photographs were taken at specified time intervals and the temperature profile was recorded continuously to provide a means for comparisons and eventually for selecting an optimal well configuration for different reservoir conditions. Experimental The two-dimensional reservoir model is that which has been described by Butler et al.(1) only with minor modifications. The schematic experimental set-up is illustrated in Figure 1. The model was scaled to the field conditions by using the method described by Butler et a1(2). The scaling parameters are shown in Table 1. One hour for the model is equivalent to 1.5 years in the field. The vertical circulating steam injector(1) was employed to initiate the communication between the injection and production well. The injection well location was adjusted vertically to allow for different steam injection locations. Figures 2a and 2b show how this vertical steam injector works. The porous materials used in the reservoir model were 2 mm and 3 mm glass beads. In order to obtain a uniformly random packing of the porous pack, the reservoir model was secured on a vibrating table.

The Design of a Modern Steamflood in a Thick, Dipping, Heavy Oil Reservoir

In 1988, Mobil completed the design phase of a new steamflood project. This project is in a thick, moderately dipping, unconsolidated heavy oil reservoir. The design takes advantage of the gravity drainage recovery mechanism in the thick reservoir, allowing vertical steam zone expansion with minimal steam breakthrough. The steamflood was designed to be economic in the late 1980's period of low oil prices. The design was completed with an interdisciplinary teamwork approach using concurrent studies for expediency. This paper was first presented at the 1989 California Regional Meeting in Bakersfield. The presentation for this meeting will conclude with an update of project performance since 1989.

Steam-Assisted Gravity Drainage Model Incorporating Energy Recovery From A Cooling Steam Chamber

Abstract A new calculation procedure has been developed which allows the prediction of the effects of varying steam injection rates, pressures, and the duration of injection cycles on heavy oil recovery by gravity drainage. Previous models assumed maintenance of a constant steam chamber pressure and temperature. The model uses an approximate mathematical method to obtain the heat transfer to the receding oil bank and to the overburden. The heat injected is balanced against the total losses from the system and surplus and deficiencies cause variations in the temperature and pressure within the steam chamber. Modelling results indicate that considerable increases in cumulative oil-steam ratios are to be gained by stopping steam injection before the recoverable reserves in a pattern have been completely produced. It is also found that higher injection pressures and rates accelerate production and do not reduce the cumulative oil steam ratio significantly. Little benefit was found to result from multiple injection cycles within the same production pattern. These results should be of practical importance in the application of this process in the field. Introduction Steam-assisted gravity drainage in heavy oil recovery is a production method which exploits the tendency of oil heated by injected steam to flow from the top to the bottom of the reservoir. Steam injected into a reservoir rises to the top due to gravity differences between the steam and the natural reservoir fluids. The heat concentration at the top of the reservoir reduces the oil viscosity in the vicinity of the steam. The mobile oil flows to the base of the reservoir driven by gravity. Gravity drainage is likely responsible for much of the oil produced in conventional heavy oil production methods(4). In horizontal steam-assisted gravity drainage, steam is injected along the length of and above a horizontal production well which is at the base of the reservoir and parallel to it. Esso Resources Canada Limited has chosen to use vertical steam injection wells spaced along the length of horizontal producers temperin some pilot experiments at Cold Lake, Alberta, where steam-assisted gravity drainage to horizontal wells is being tested in the Clearwater formation(5,6). For application to the recovery of bitumen from tar sands deposits, such as those that exist in the Cold Lake, Athabasca and Peace River deposits in Alberta, steam can be introduced into the reservoir by the creation of a fracture(1,5). The bitumen cannot be displaced because it is not mobile at reservoir conditions. The assumption of an initial vertical fracture extending from the injection well to the top of the reservoir is convenient to the modelling process because it avoids the difficulties associated with instabilities of a steam chamber rising vertically counter-current to a flow of oil(1). In a large-scale, horizontal-well, gravity drainage system, groups of injection and production wells would be placed in parallel rows so that steam chambers growing from adjacent patterns would eventually encounter each other and merge.

Assessment of Flash Vessel Design

This paper proposes a method of assessing the size and rating of vertical and horizontal steam flash vessels for a range of pressures up to 25 bar using droplet separation theory.

The Use of Solvents And Gases With Steam In Tbe Recovery of Bitumen From Oil Sands

Abstract The use of the CO2, ethane and/or naphtha together with steam was investigated as a means of improving recovery and other operating parameters in the interwell vertical steamstimulation process for recovery of bitumen from oil sands. A total of sixty-three experiments were conducted using a two-well, 45-cm-diameter, three-dimensional elemental physical simulator operating at an overburden pressure of 3.5 MPa. The results of twenty of these experiments are presented. By examining the results, the major mechanisms by which recovery occurs were determined and the impact that these mechanisms would have on field operations are discussed. Introduction The Athabasca deposit of the Alberta Oil Sands is one of the major petroleum deposits of the world. Its high viscosity (5,000,000 cps at reservoir conditions) and high bitumen saturation and hence low injectivity, however, provide some unique recovery problems. Because of its high viscosity, the bitumen has no mobility and cannot be moved forward by an advancing fronts because of its high bitumen saturation, there is limited access to the deposit to enable the entry of agents such as heat, solvents, gases, surfactants and bacteria which could alter the viscosity of the bitumen. The Alberta Research Council has developed a process whereby access to the deposit is initially achieved by using hydraulic fracturing or horizontal boreholes near the base of the deposit. These initial communications are then expanded to provide a hot communications path between injectors and producers. A cyclic process is then initiated involving pressure build-up and depletion cycles, whereby the heated front is forced to progressively move up the formation thereby achieving bitumen recovery. The process has been termed interwell vertical steam stimulation. In earlier work reported by Redford and McKay(1), it was shown that the process, when operating at 2.1 MPa, was substantially improved by the addition of hydrocarbons to the steam. This work has now been extended to the study of CO2 and ethane, the combination of CO2 and hydrocarbons, and a study of the recovery mechanisms taking place. Experimental Equipment The experiments were conducted in a three-dimensional elemental model referred to as the 45-cm simulator which has been briefly described elsewhere(2,3). The term "elemental model"(4) indicates that the experimental approach is to take an element of the formation and to conduct experiments on that element at conditions comparable to field operating conditions. This type of model is useful for screening a wide variety of recovery processes, but accurate scaling of the experimental results to predictions of field performance requires a complicated mathematical manipulation of the data. (By contrast, the results from a scaled model may be more easily transferred to field performance predictions, but the problem is to design the model in the first place.) The simulator (Fig. I) is a cylinder, 45 cm in internal diameter and 40 cm in height, capped at each end with blind flanges. The vessel is equipped at the top with a piston which is used to apply an overburden pressure of up to 7 MPa on the oil-sands pack.

Steam Drive Model for Hand-Held Programmable Calculators

Summary This paper presents a model based on works published by Van Lookeren and Myhill and Stegemeier. The first portion of the model calculates an optimal steam rate (to the nearest 5 B/D) for a given set of steam and reservoir parameters by the method proposed by Van Lookeren. The second portion of the model uses the optimal steam rate (or a given steam rate) and related data calculated in the first portion in conjunction with additional inputs to calculate the oil production history. A modification to the Myhill-Stegemeier model is introduced that significantly improves correlation of model predictions with field results in 14 projects reported in the literature. Included in the paper Is a complete program listing for Texas Instruments Inc.'s TI-59 calculator with a PC-100 printer, as well as operating instructions and an example problem. Introduction For many years, various investigators have attempted to provide steamflood models that yield acceptable results yet are applied readily by the average engineer. These calculation methods have taken several forms including (1) a digital computer program by Effinger and Wasson and a "cookbook" graphical method proposed by Fairfield, each presenting easier ways of applying the basic Marx and Langenheim steam-zone growth model, (2) analytical models by Mandl and Volek, Neuman, Myhill and Stegemeier, and Van Lookeren that account for gravity override and steam-front shape factors ignored in the simpler models, and (3) a novel curve-matching model by Gomaa based on parametric studies done with a numerical simulator. All of these methods have drawbacks ranging from oversimplification to cumbersome application, and most include significant handwork for more than a few calculations.An obvious need exists for a model that can be used on a hand-held calculator with as much automatic documentation and as general application as practical. This paper presents such a model for use with a TI-59 programmable calculator and a PC-100 printer. Model Description Injection-Rate Optimization Model The model consists of two integrated components that can be used separately or as a set. The equations for the first component are described in detail in Appendix A, with user instructions in Appendix B. The purpose of this program is to calculate and document steam parameters including Ts, Ps, is, fs, hn, degrees API, and ks. Eq. A-1 is the same equation proposed by Van Lookeren for calculating the effects of segregated flow on vertical steam sweep efficiency. This equation can be used to optimize steam injection rate if the investigator has access to pressure vs. rate data for a given injection project.With such data, it is possible to calculate a maximum EI as a function of an optimal injection rate, which Van Lookeren shows maximizes vertical sweep. It is assumed that the various injection parameters remain constant so initial injectivity tests in a new project probably will not be very useful. However, experience has shown that useful pressure/rate extension data are available when cold-oil-viscosity-dominated cold-oil-mobility effects subside and reservoir-permeability-dominated hot-oil mobility controls injectivity, usually within a year of continuous injection. JPT P. 1583^

An Experimental Study of Heat Flow in Steam Flooding

Abstract An experimental study of beat flow in steam flooding was carried out with steam displacing water in a plane-radial fluid-flow model. Temperature distributions in the model reservoir, overburden, and substratum were measured at frequent intervals during flooding by means of a fixed array of thermocouples. Heat losses to overburden and substratum and the division of beat between The steam and hot-water zones in the reservoir were calculated from the temperature data by performing numerical integrations over the appropriate volumes. Temperature profiles and heat distribution results are presented. Some results were (1) the traction of injected beat that is lost to overburden and substratum, when expressed as a junction of time, did not depend on injection rate; (2) a significant portion of the injected heat was contained in the hot-water zone ahead of and underlying the steam front in the reservoir. The division of beat between the steam and hot-water zones did depend on injection rate; and (3) considerable gravity override was observed. The experimental results are compared with those of several published theoretical studies of beat transfer in hot-fluid injection; approximate agreement on beat losses is found with some of the most idealized theories. A valid comparison cannot be made in regard to steam vs hot-water zone; basic interpretation of the hot-water zone, in terms of a vertical steam front, is clouded by gravity override in the experiments. Introduction The experimental study reported here primarily concerns two problems of heat transfer in steam Hooding that have economic and engineering importance. These are (1) the fraction of injected heat lost to the overburden and substratum, and (2) the division of the remaining heat between a zone containing steam and a zone of hot water at lower-than-boiling temperature. The volume of the steamed region, which has a direct effect on oil recovery, can be calculated reads, born these resin. Several valuable theoretical studies have been published on this problem, but no experimental tests of the theories have previously appeared. Tests were needed because the effects of the necessary simplifications in the theories could not be determined otherwise. The basic, untested theoretical problem is the effect of "decoupling" heat and mass transfer and the resulting inability to include the effects of heat transfer and condensation on fluid flow. The theoretical problem solved so far has been a heat transfer problem in which fluid is present as a heat carrier and flows in a stipulated manner, either linear or plane-radial. The simplifications that have sometimes been made in regard to thermal conductivity by, for example, Marx and Langenheim, Lauwerier and Thomas apparently do not have an important effect on heat loss calculations, although the results of the different methods disagree to a certain extent, as shown by Spillette and by Ramey. A recent paper by the authors compared the results of experiments in hot-water flooding with several theoretical results and showed a rather poor agreement. It will be seen that the poor agreement. It will be seen that the experimental heat loss results for steam flooding, however, show acceptable agreement. These comparisons are discussed in a later section.