A Study of Steam-Assisted Gravity Drainage Performance in the Presence of Noncondensable Gases

Noncondensable gas steam-assisted gravity drainage

Horizontal wells are gaining increased prominence in primary recovery and steam injection, yet experimental and theoretical modelling of horizontal wells is still inadequate. This paper explores these two areas. Equations were developed for three-phase and non-isothermal flow in the vicinity of a horizontal well, as well as flow inside the well. These were used to obtain scaling criteria for designing laboratory experiments. The question of skin factor due to perforated casing is also considered. An interesting idea offered is the use of variable diameter horizontal wells. A series of steam injection experiments was carried out in a model, with a concentric well. Temperature distributions were determined and used to interpret oil recoveries and pressure behaviour. Oil recovery performance for different experiments was evaluated to determine the effectiveness of different types of horizontal wells, and the impact of perforated casing. Introduction It has been reported extensively(1,2) that horizontal wells offer prospects of improved performance over conventional vertical wells, primarily due to the larger contact area between the formation and the horizontal well. This is especially true for thin oil formations where the reservoir contact area for a horizontal well can be hundreds of times that for a fully-penetrating vertical well, Furthermore, horizontal wells, when strategically placed, can reduce water/gas coning and result in improved cumulative recovery in view of the small draw downs(3). Horizontal wells are also believed to have a much better chance than vertical wells of intersecting systems of vertical and horizontal fractures in an oil-bearing formation, and thus lead to higher production rates(4). In steam injection recovery of heavy oils and oil sands horizontal wells especially when combined with steam-assisted gravity drainage could lead to high production rates, more uniform distribution of steam front leading to improved sweep efficiency and cumulative oil recovery(5,6). One aspect that has so far received little attention in discussions of horizontal well performance concerns the flow in the vicinity of, and inside a horizontal well. Often, it has been assumed that a horizontal well has infinite conductivity and that the flow in the well is predominantly laminar - meaning the pressure drop across [he well is not significant. Dikken(7) showed that this assumption is not necessarily true for most practical situations, and that pressure drops across horizontal wells can significantly affect the performance. This paper attempts to contribute to an understanding of this aspect of horizontal wells by presenting mathematical models of flow in the vicinity of, and inside a horizontal wellbore. These models were used to obtain scaling criteria for a series of scaled model steam injection experiments. Data, including well pressure drop and fluid production rates in the presence of a perforated casing are also reported. Literature Review Butler, McNab, and Lo(5) presented the first theoretical and experimental study of steam-assisted gravity drainage and horizontal wells to recover bitumen from oil sands. Equations were derived to calculate oil drainage rate and lateral position of steam-oil interface as functions of time and height. A subsequent study by Butler and co-workers(H) introduced improvements to the original model.

Steamflooding with horizontal wells promises to be a highly effective method for recovering heavy oils from shallow, thin formations. As is often the case for poorly consolidated heavy oil formations, sand production could constitute a serious production engineering problem. For horizontal wells, this problem could be exacerbated as the sands/formation fines could settle inside, and choke off sections of a horizontal well completely - leading to loss of production. To alleviate this problem, it is often necessary to case the horizontal wells. This paper reports results of a series of scaled model steam injection experiments investigating the role of a perforated casing on the recovery performance. Fluid production rate, well pressure drop, cumulative oil recovery and cumulative oil-steam ratio for open and cased horizontal wells are determined and compared to determine the impact of the casing. It is concluded that a casing, though necessary to control sand production into a horizontal well, could lead 10 lower cumulative oil recovery and lower thermal efficiency for the recovery process. For example. oil recovery and the cumulative oil-steam ratio in the absence of a casing were 49.7% of IOIP and 0.62, respectively. The corresponding values in the presence of a casing were 42.9% and 055, respectively. Introduction With innovations in lateral and horizontal drilling technology, more horizontal wells are being used to recover oil and gas world-wide. It has been widely recognized that the main advantages of horizontal wells over conventional vertical wells include larger reservoir contact area, ability to reduce the effects of gas/water coning, as well as the higher probability to intersect systems of vertical fractures in fractured reservoirs. In thermal recovery applications, horizontal wells - due to their extended contact with the reservoir - promise high production rates and improved steam sweep efficiency. For these reasons, many thermal horizontal well projects have been started up, and field-tested in Alberta and Saskatchewan 1–3. The main production mechanism for the AOSTRA Underground Test Facility (UTF) in Fort McMurray, Alberta is steam-assisted gravity drainage. The pilot has been so successful that an expanded Phase B which involves more and longer horizontal wells is being implemented for commercial operation 1. For Esso Canada Resources Ltd. 's Cold Lake horizontal well project, the first phase of operation involves cyclic steam stimulation of vertical wells to provide steam injectivity. Steam is then injected down these vertical injectors to push oil towards the horizontal producer 2. Scepcre Resources Ltd.'s North Tangleflags, Saskatchewan pilot 3 also utilizes vertical steam injectors to mobilize and displace the heavy oil into a long horizontal producer. Sand production is perhaps the most widespread and costly production problem associated with many thermal recovery projects. The sand and formation fines could either impair production by choking the wellbore or reduce production by preventing the proper operation of downhole pumping equipment. Also, they will require the replacement of equipment because of erosion damage 4.

Simulation and evaluation on enhanced oil recovery for steam huff and puff during the later phase in heavy oil Reservoir—A case study of block G in Liaohe oilfield, China

Experimental study and numerical simulation of urea-assisted SAGD in developing exra-heavy oil reservoirs

This paper presents- an experimental investigation of the! effect of horizontal-vertical well configuration on oil recovery of Safanyia crude by alkaline flooding. Emphasis was focussed on the effect of horizontal well pattern on oil recovery. Also, the effects of three types of alkali solutions; sodium- carbonate; (Na2CO3) sodium ortha-silicate (Na4SiO4). and sodium hydroxide (NaOH) on cumulative oil recovery, in both secondary and tertiary processes using linear model, vertical- vertical two dimensional model, and horizontal-vertical schemes, were investigated. It was found that displacing Safanyia crude oil by NaOH solution having 1% concentration results in higher oil recovery in both linear and horizontal-vertical schemes. The highest oil recovery through horizontal-vertical schemes was obtained by, placing the horizontal well perpendicular to the line connecting the two vertical wells with a length that does not reach the boundary of the reservoir- Also, it was found that oil displacement efficiency in the tertiary process is higher than in the secondary process. Introduction The use of horizontal wells has been increasing very rapidly throughout the oil industry as advances in drilling techniques continue. In many reservoirs, horizontal wells can solve a number of oil production problems. However, in spite of a tremendous increase in literature references, little information is available on horizontal well applications in enhanced oil recovery (EOR) methods(1). Many published articles show that horizontal wells are still used primarily to solve specific production problems, These include low permeability formations especially fractured formations low permeability gas reservoirs, unusual gas sources, gas or water coning, thin formations, and viscous oil(2,3). Most horizontal well applications of EOR activities have been in the area of thermal recovery, primarily for steam stimulation and steam drive(4,5). Although there is relatively little published information on the use of horizontal injection wells, other than thermal recovery the for patterns of both horizontal injection and vertical production well, to increase the rate of flooding in EOR has been mentioned(6,9). Early laboratory work oncaustic flooding through horizontal wells (10) showed that the use of a horizontal wellas an injector in alkaline flooding increased oil recovery by a minimum of 8% o initial oil-in-place (IOIP) compared to vertical wells. This paper studies the effect of horizontal 0vertical well configurations in one uater of a five-spot pattern model on oil recovery by alkaline flooding. It also discusses the effect of alkaline type and concentration on oil recovery in secondary and tertiary processes. The study was not made ina scaled model. Instead, Safanyia crude oil from Saudi Aramco has been used to investigate qualitatively the effect of horizontal-vertical well configuration in one quarter a five-spot model. Experimental Work Fluid Properties The physical properties of the fluids used in this study are shown in Table 1. The crude oil is Safanyia crude received from Saudi Aramco. The oil has an acid number of 1.5 mg KOH/g crude oil. The oil acidity was measured according to IP 1/74 test analysis which is equivalent to ASTM D974 test (11).

Steam assisted gravity drainage (SAGD) is one of the more popular enhanced oil recovery method of producing heavy oil and bitumen. In conventional SAGD approach, steam is injected into a horizontal well located above a horizontal producer. A steam chamber grows around the injection well and displaces heated oil toward the production well. There are several variations of this process: vertical injector-horizontal producer and singlewell (SW) SAGD where only one horizontal well is used by injecting steam from the toe of the horizontal well with production at the heel. Some advantages of technically challenging process include cost savings and utility in relatively thin reservoirs. To improve early-time response of SW-SAGD, it is necessary to heat the near-wellbore area to reduce oil viscosity and allow gravity drainage to take place. This paper investigates the optimization of the startup procedure for SW-SAGD as the project economics are influenced significantly by the early production response. An experimental investigation of two early-time processes namely cyclic steam injection and extreme pressure differential between injector and producer to improve reservoir heating, is discussed and compared to other well configurations. Crushed limestone saturated with heavyoil 12.8 °API) and water that was packed in a semi-scaled laboratory model is used for the experiments. The effectiveness of the methods are compared within themselves and to conventional SAGD by measuring the size of the steam chamber as a function of time. It is found that the steam chamber area for cyclic steam injection is slightly greater than that of extreme pressure differential case. Furthermore, numerical simulation studies of different early time processes are performed and compared to experimental data using a commercial simulator. It was observed that the numerical model results underestimated the cumulative oil recovery and the steam chamber size. Results from this study, including cumulative recoveries, temperature distributions, and production rates display the differences among the methods. Introduction Gravity drainage of heavy oils in situ recovery processes is of considerable interest in oil industry. Since these oils are very viscous and almost immobile, a recovery mechanism is required by which the viscosity of the material is lowered to the point where it can flow to a production well. Conventional thermal processes, such as cyclic steam and steam assisted gravity drainage (SAGD) (1,2,3,4) are based on thermal viscosity reduction. Cyclic steam incorporates a drive enhancement from thermal expansion. On the other hand, SAGD is a process based on gravity drainage and horizontal wells. In this process, a growing steam chamber forms as steam is injected from a horizontal injection well into the reservoir and steam flows continuously to the perimeter of the chamber where it condenses and heats the surrounding oil(1). Heat is transferred by conduction, convection, and by latent heat of steam. The heated oil drains, driven by gravity, to a horizontal production well located at the base of the reservoir just below the injection well (1) as shown in Figure 1. This process is effective and can be economic if the steam requirements are too high (5).

While SAGD (Steam Assisted Gravity Drainage) can be used to recovery heavy oil from strong bottom water drive reservoir, the bottom water is known to have a detrimental effect on the SAGD performance, may cause unsuccessful SAGD application. During SAGD process, the common practice to control the water encroachment is to keep the steam chamber pressure at or above the aquifer pressure. At higher pressure, less latent heat is available, leading to unprofitable SAGD project with low oil production rate and low oil recovery. In this paper, an innovative approach is proposed to tackle the problem by combining the use of SAGD with DWS (Downhole Water Sink). The concept of DWS is the first to be integrated into SAGD production process. With a new type of well completion design, along with the two separated wells of SAGD, another well is completed in the water zone to decrease the aquifer pressure through continuous water production. As the aquifer pressure decreasing, low steam chest pressure can be maintained, thus allowing for more latent heat available in the formation which would ensure high oil rate and high oil recovery. A theoretical study of SAGD-DWS performance on improving heavy oil recovery is conducted in this paper. A design model is developed to predict the optimum ranges of the SAGD-DWS production parameters under various operation scenario. The effects of the new approach on increasing oil rate and improving oil recovery in comparison to that of conventional SAGD are quantified. The results demonstrate that unlike other thermal recovery methods, the combined use of SAGD with DWS can prevent the water invasion into the steam chamber while allowing for low steam chamber pressure with high heat efficiency.

A comparison of three thermal EOR processes; SAGD (Steam Assisted Gravity Drainage), HASD (Heated Annulus Steam Drive) and CYS (Cyclic Steam Stimulation), has been made using a three dimensional thermal simulator by employing a combination of vertical and horizontal wells. Reservoir characteristics and thermal and fluid properties were maintained identical for process comparison. A 10-year project-time study was undertaken for CYS with vertical wells, CYS with horizontal wells, HASD with horizontal HAS pipe and aligned vertical injector and producer, HASD with offset vertical producers, and SAGD with horizontal injector and producer. The effect of reservoir heterogeneities on process performance was also examined. CYS vertical performed significantly better than CYS horizontal both in terms of cumulative % OOIP recovery and SOR. HASD recovered more oil, though the initial production rate in HASD was low. SOR in HASD was, however, very unfavorable (more than twice that of CYS vertical). HASD with offset wells made both SOR and % OOIP recovery more favorable. SAGD had better SOR than HASD; however, it recovered about half the oil recovered by HASD at the end of ten years. An unfavorable heterogeneity feature (low permeability layers or barriers) affected the recoveries and SORs for the horizontal well processes more adversely than vertical well processes.

Effect of well pattern and injection well type on the CO2-assisted gravity drainage enhanced oil recovery

The technical performances of horizontal and vertical wells were examined for a tertiary, carbon dioxide miscible flood in a 240-acre (97 ha) area of a west Texas field using a black-oil, pseudo-miscible simulator. Although a 40 acre (16 ha), inverted five-spot pattern was used initially for both vertical and horizontal wells, the spacing was increased to 80 acres (32 ha) for the horizontal wells to maintain the miscibility pressure in the reservoir. Horizontal injection and production wells, 1,320 feet (402 m) in length, completed at the bottom of the formation, recovered 14 to 22 percent more oil than vertical wells. Economic analyses for the horizontal injectors and producers were compared to economic analyses conducted for vertical injectors and producers. Project economics were significantly effected by the capital expense for drilling new wells. The vertical wells provided the better rate of return if no new drilling- or only one new well for every six patterns was required. If horizontal wells could be drilled from existing vertical wells- or from the surface at 1.5 times the cost of vertical wells, the rate of return was comparable- or better than vertical wells requiring one new well for every three patterns. Horizontal wells drilled from the surface at twice the cost of vertical wells provided the lowest rate of return.

The experiments on initial stages of steam assisted gravity drainage(SAGD) process have been carried out using two-dimensional scaled reservoir models to investigate its production process and performance. Rising or growing process of the initial steam chamber, its shape and area, and temperature distributions have been visualized by using video and thermal-video pictures. As a drainage mechanism, the relationship between isothermal lines and chamber interface have been presented. The temperature on the interface, where the chamber was expanding, was maintained at almost constant temperature of 80 C. Furthermore, the effect of vertical well spacing between two horizontal wells on oil recovery has been investigated. For the case of usual SAGD, oil production rate increases with increasing vertical well spacing, however the leading time to start oil production by gravity drainage becomes longer. The results show that the well spacing may be a representative length for initial stage of the process. Based on these experimental results, a modified SAGD process by adding intermittent steam injection from the lower production well have been proposed. By applying the modified process, the time to generate near break-through condition between two wells was relatively shorten, and oil production was enhanced at the stage of rising chamber compared with that of usual SAGD process. Introduction There are vast heavy oil and oilsands reserves not fully exploited, because it is not easy to produce heavy oil efficiently and economically. However, steam-assisted gravity drainage (SAGD) process has been successfully applied to oilsands fields. The process has been developed by Butler and his co-workers. Their ideas was to overcome the problems associated with the highly viscous bitumen by gravity drainage in steam chambers generated by displacement of heavy oil. As shown in the reports on the UTF projects (phase A and B) in Canada, the SAGD process (see Fig. 1) has proven to be very superior process for the recovery of the bitumen due to its high recovery factor. Chung and Chung & Butler have reported experimental results for SAGD process with scaled and visual reservoir models. Furthermore, Chow & Butler have reported the numerical simulation results matching the Chung's experimental results with the STARSTM. Recently, Mukherjee have reported the successful forecast of the performance for the phase B of the UTF project. Butler gives an excellent review of the SAGD process. In this paper, the SAGD process operated by steam injection from upper well and production from lower well like that of UTF project, is hereinafter referred as "usual SAGD." A problem of the usual SAGD process for oilsands reservoirs is leading time to generate a steam chamber in near break-through condition between two horizontal-wells before production stage by rising and expanding chamber. The more economical SAGD production should be achieved by a modified process to shorten the period of initial stage and enhanced steam injection for effective usage of steam generation and production facilities. First, we have investigated characteristics of the usual SAGD process, especially expanding rate of steam chamber by gravity drainage and effects of vertical well spacing on it. It was found that by using shorter vertical spacing between two wells, leading time is reduced while production rate after break-through becomes lower. Based on experimental results, a modified process has been proposed to start oil production earlier and enhance oil production at higher rate after break-through. In this process, steam is injected from both of upper and lower wells. Then, the lower well has both functions of production and steam injection, which is similar to the single SAGD well developed and reported by Liderth. The steam is injected intermittently from the lower well, because steam injection holes and oil production holes at the well are quite close to prevent steam break-through. P. 467

The Du 84 block of the Shu-1 area in the Liaohe Oil Field is located in Panjin City, Liaoning Province, China. The production formation, Guantao, contains extra heavy oil with a depth of 530–640 m. The reservoir is characterized in thick pay, with high permeability and a very active aquifer. The dead oil viscosity is 230,000 mPa.s at 50 °C. Although the Cyclic Steam Stimulation (CSS) process using vertical wells has been applied successfully in producing oil from the reservoir, the anticipated ultimate oil recovery is less than 29% of the original oil in place (OOIP). To enhance oil recovery beyond that of the CSS, physical and numerical modeling studies were carried out. The Steam Assisted Gravity Drainage (SAGD) process using a combination of vertical and horizontal wells was proposed as a follow-up process to CSS. An additional 27% recovery is anticipated with the proposed follow-up process. This would give a total recovery of 56%. A pilot with four horizontal producers was implemented in the field. CSS was used initially in the horizontal wells for establishing the communication with the surrounding vertical wells. The pilot was then converted successfully to SAGD operations with horizontal wells as continuous producers and some of the surrounding vertical wells as continuous injectors. A total of 44,500 m3 of oil has been produced over the 12 months of SAGD operations between June 2005 and June 2006. The field implementation process and pilot performance, as well as the challenges with this project, are presented in this paper. Introduction This paper is the continuation of an earlier work(1) in which a field pilot was proposed for testing Steam Assisted Gravity Drainage (SAGD) as a follow-up process to CSS based on a reservoir model and feasibility studies. Two field pilot projects were constructed in 2003 in the Du 84 block of the Su-1 area in the Liaohe Oil Field. One pilot is producing from the Xinglongtai formation and the other one is producing from the Guantao formation. The pilot in the Guantao formation was converted to SAGD operations in early 2005 and the field results are encouraging. The field performance from this pilot is reported in this paper. The Steam Assisted Gravity Drainage (SAGD) process, which was described by Dr. R.M. Butler in the late 1970's(2), has been applied successfully for the production of bitumen and heavy oil since it was tested in the Underground Test Facility (UTF) in the Athabasca oil sands of Alberta, Canada(3). Several commercial projects have been implemented in the field in Canada since then. The Liaohe Oilfield Company constructed its first SAGD pilot in China in 1996 in the Xinlongtai formation, which contains extra heavy oil at a depth of 750 m from the surface. The pilot consisted of one stacked well pair and was operated for about one and a half years. The suspension of the pilot test was due to:insufficient lift capacity provided by the gas lift system; and,difficulties in communication resulting from too large a vertical separation between the injector and the producer.

Experimental study of core size effect on CH4 huff-n-puff enhanced oil recovery in liquid-rich shale reservoirs

In the steam assisted gravity drainage (SAGD) process, the addition of small amounts of non-condensable gases to steam may improve oil recovery. The gas accumulates at the top of the reservoir where it provides an insulation effect and forces the steam chamber to spread laterally. The result is a more efficient use of steam and the potential for greater recovery of oil. Six experiments were conducted in two different geometries to study the effect of non-condensable gas on the performance of SAGD. These experiments consisted of steam-only, steamcarbon dioxide and steam-n-butane injection. Three SAGD experiments were carried out in a scaled 3-D model packed with crushed limestone premixed with a 12.4 °API heavy crude. In these experiments, the steam-only case had the highest recovery, as expected. However, using carbon dioxide or nbutane with steam reduced the steam consumption. In both those cases, recovery was lower than the steam-only case. The other SAGD experiments were carried out using limestone core plugs saturated with the same heavy oil. Similar trends were observed for core plug experiments; however, the recovery was better when n-butane was added to steam. The presence of n-butane had a positive effect on the oil recovery and required less steam consumption than the other two cases. ifferences between the experiments were identified by means of analytical modeling. All the experiments were modeled with respect to Butler's SAGD theory and Reis' linear model. The results of the 3-D experiments were matched by all models, whereas the results of the core scaled experiments were better represented with Reis' linear model because of the heterogeneity present in the core plugs. The addition of non-condensable gas to steam in a SAGD operation was evaluated using physical models of different geometries. The experimental results indicated that for both geometries, steam consumption was reduced by using either carbon dioxide or n-butane. More experimental studies are needed to asses the effect of non-condensable gas addition on increasing oil recovery. Introduction The basic mechanism of the SAGD process for heavy oils was initially proposed and demonstrated by Butler. It is based on simple physical concepts: rising steam heats the formation and hot liquids flow downward. Generally a large portion of the original oil in place can be produced by gravity drainage, resulting in low residual oil saturation. In this process, parallel horizontal wells are used for both injection and production due to the large contact area that they provide for the process. The steam is injected through the upper well, where it condenses on the cold sections and heats the oil. The viscosity of heavy oil decreases the oil becomes mobile and drains by gravity with the condensed steam to the lower production well1. A major limitation of SAGD is the requirement for a large amount of steam, particularly in thin, low quality reservoirs. This means that high energy is required for production of continuous steam. Das and Butler proposed that this limitation could be avoided or decreased in two ways: