Steamflood Pilot Research Articles

Simulation Of The Saner Ranch Fracture-Assisted Steamflood Pilot

Abstract Conventional steamflooding of heavy oils and tars in thin reservoirs generally suffers from excessive heat losses to the over- and under-burden. High rate steam injection is often constrained by limited reservoir injectivity. A recently developed FAST process (Fracture-Assisted Steamflood Technology) allows high rates of steam injection in thin shallow sands through hydraulically created horizontal fractures. This process limits the heat losses by shortening the steamflood life for a 5 to 7.5 acre (2 to 3 ha) pattern to less than two years. Conoco demonstrated the technical feasibility of the FAST process in two pilot tests in south Texas where −2 ° API (1 093 kg/m3) tar was successfully produced. In an attempt to understand the dominant flow mechanisms in the FAST process and to develop a technique for predicting performance of future FAST steamfloods, numerical simulation was used to achieve a comprehensive history match of the second pilot test at the Saner Ranch in south Texas. Despite the complexity of this recovery process, a commercially available steamflood simulator was used to match the performance of one-twelth symmetry element of the inverted 7-spot, 7.5 acres (3 ha) pattern. In addition to matching the tar and water production, the temperature and pressure histories, temperature profiles, water cuts and volumetric tar recoveries were also matched. One of the key elements was the modeling of multiple phase flow through an open fracture. This was accomplished by a simple technique which did not require reprogramming of the conventional steamflood simulator. The numerical simulation of the FAST process revealed dominant flow mechanisms in the process. The calibrated model is now being used for on-going predictive and process optimization studies. This paper briefly describes the FAST process, pilot history, details of the technique used to model flow in an open fracture, and results of the numerical modeling study. Introduction Conoco conducted two pilot tests of the FAST steamflood process in the south Texas tar sands deposits (Fig. 1). These formations contain −2 ° to + 3 ° API (1 093 to 1 052 kg/m3) tar with viscosities of 1 to 20 million centipoise at reservoir temperatures. The first pilot was conducted from November 1977 to June 1980 at the Street Ranch lease where 169,040 barrels (26 875 m3) of −2 ° API (1 093 kg/m3) tar were recovered from a 5-acre (2 ha) pattern after injecting 1,847,500 barrels (293 730 m3) of steam(1). The second pilot test was conducted at the Saner Ranch from April 1981 to January 1983. A total of 133,260 barrels (21 190 m3) of tar was recovered from a 7.5-acre (3 ha) pattern after injecting only 1,069.000 barrels (169 950 m3) of steam(2). The main objective of the first pilot was to prove the feasibility of the FAST process for recovering −2 ° API (1 093 kg/m3) tar. The objectives of the second pilot test were to demonstrate the FAST process in a different part of the reservoir and to improve performance.

Thermal Recovery of Heavy Oil at Edison Field, Bakersfield, California: ABSTRACT

Thermal recovery of heavy oil is, to date, the most successful enhanced oil recovery process. Both steam stimulation and steam-flooding are widely used in California. They add almost 300,000 BOPD to the state's production. The Edison field, located on the eastern side of the San Joaquin valley, is just one of many heavy oil fields being produced by thermal recovery methods. The Edison heavy oil sands are offshore-bar and alluvial-fan deposits. There are two textural controls on the reservoir quality of these rocks: (1) grain sorting and (2) the amount of dispersed silt and clay. The reservoir properties affected by rock texture are permeability and capillary pressure. Capillary pressure is particularly important, as it traps oil, controls oil saturation, and limits oil mobility. The heavy oil at Edison is currently being produced by cyclic steam stimulation. The heat from the steam improves production by lowering the viscosity of the oil. Steam stimulation has doubled the recovery of heavy oil. The enhanced oil recovery project at Edison was recently expanded to include a pilot steam-flood. The pilot project was designed with the aid of a computer model. The model was used to simulate the movement of steam through the reservoir and predict oil and water production. Simulated production trends indicate that the success of the project will depend on the oil saturation in the reservoir at flood start. Steam injection into the pilot site began in February 1982. It is just one of many enhanced oil recovery projects being attempted by industry to try and offset a steady decline in new oil field discoveries. End_of_Article - Last_Page 1694------------

Monarch Sandstone: Reservoir Description In Support Of A Steam Flood Section 26C, Midway-Sunset Field, California

Abstract Study of the Monarch sandstone in the vicinity of the 26C Steam Flood Field Trial shows the sand to consist of a series of turbidites which have experienced contemporaneous structural deformation and subsequent erosion. Knowledge of the local basin topography at time of deposition allows a prediction of permeability orientation to be made. A reduction in vertical permeability associated with diatomites deposited between turbidites is noted. The preservation of these diatomites is related to the erosional energy possessed by subsequent flows. Quiescent periods during deposition of this sequence deposited thick diatomites in some areas of the field. The mapping of these diatomite "swarms", together with the inferred permeability orientation, allows a prediction to be made regarding the behaviour of the injected fluid in the subsequent steam flood. Introduction The Monarch sandstone in section 26C, 32S, 23E, Kern County, California, was placed on steam drive in November 1975 after an extended period of primary production and cyclic steam-enhanced recovery. Prior to steam injection, cores were obtained from wells 26C 0–1 and 26C 0–2, which were drilled as temperature observation wells (Fig. 1) and cored both as an aid to better reservoir description and to evaluate coring methods in unconsolidated sandstone, A third well, 26C- 0–3, was also completed as an observation well. Well 26C 0–3 is on strike with injector 67W; 0–2 and 0–1 are respectively farther updip. The steam flood field trial was designed to test steam drive in a steeply dipping (10-degree), thick (300 feet), heavy oil reservoir. Reservoir and fluid characteristics are summarized in Table 1. Gomaa, Duerksen and Woo (1976) detailed the first attempts at predicting the pilot performance using Intercomp's steam flood simulator. A companion paper (Duerksen, Gomaa, 1977) addresses the progress of this flood and documents field evidence for the validity of this reservoir description. The reservoir description is approached with steam drive in mind, cognizant that gravity override is the major concern in steaming thick zones. Regional Structures, Unconformities The 26C steam flood pilot is located on the southwest flank of the SpelIancy anticline (Fig. 2), a portion of the Midway-Sunset field. The structural axis strikes ENE; theanticline plunges ENE at 6 to 7 degrees. Dip on the SEflank of the pilot area is =10 degrees. The Monarch sandstone averages = 350 feet thick over the field trial area. Two major unconformities truncate the sandstone (Fig. 2). The post-Pliocene Etchegoin unconformity erodes the Monarch over the crest of the structure; the Pleistocene Tulare unconformity causes an even more abrupt truncation to the SW. In the area of the field trial, the Monarch is free of erosional and faulting effects, excepting the most updip portion. General Stratigraphy The Monarch saindstone is the arenaceous equivalent of the silty, and diatomaceous Antelope shale. It is of Upper Miocene, Upper Mohnian age and is correlated with the Stevens sand to the northwest. Elsewhere in Midway-Sunset it may be called the Spellancy Sand or the Marvic.

Designing a Steamflood Pilot in the Thick Monarch Sand of the Midway-Sunset Field

This paper describes the design and development of a steamflood pilot consisting of six inverted five-spot patterns in Section 26C of the Midway-Sunsetfield. Steam injection will be in the 330-ft Monarch sand. A steamflood simulation study indicated a potential of 60- to 70-percent oil recovery and defined the relative importance of various steamflood parameters. Introduction The reservoir characteristics and production history of Section 26C of Midway-Sunset field make it a favorable candidate for thermal recovery. Current well productivity under cyclic steaming is only about 0.05 BOPD/ft. The estimated ultimate recovery by this method is only 15 percent because of its continuously decreasing percent because of its continuously decreasing effectiveness. Underground combustion is thought to be undesirable for this section because of the reservoir's large thickness and low dip. Based on its predicted and actual performance in other heavy oil reservoirs, performance in other heavy oil reservoirs, steamflooding is the most promising thermal recovery technique for this property. The high capital and operating costs of steamflooding made a pilot desirable to evaluate the process in this field. Other reasons were uncertainties about the geological structure, sand continuity, and the role of gravity override in steamflooding a very thick reservoir. This paper describes the reservoir and its geology, the production history under cyclic steaming, pilot project production history under cyclic steaming, pilot project details, and the results of a simulation study to optimize steam injection and predict performance. Reservoir Characteristics Geology The structural feature associated with the various productive zones in Section 26C of Midway-Sunset field is a productive zones in Section 26C of Midway-Sunset field is a large southeasterly plunging nose. The main productive sands lie on the southwest flank and plunge, where the dip is about 10 deg. . Little production comes from the northeast flank, where the dip is up to 50 deg. . The two areas are separated by a thrust fault that offsets the oil-water contact. A northeasterly trending sand channel in the northern half of the section is developed and productive mainly over the northwest quarter. No production comes from the southwest comer of the section because of sand truncation. The Monarch sand, considered the main productive zone, is of Miocene age and is at an average depth of 1,300 ft. Its thickness varies from 0 to 600 ft and averages 350 ft in the main productive area. Well logs show that the sand is vertically continuous, without any significant shale breaks. A typical induction-electric log is shown in Fig. 1. However, recent cores contain a number of diatomite beds from 0.25 to 6 in. thick. Their areal extent and ability to restrict vertical fluid movement are not known. Rock and Fluid Properties The reservoir rock is an unconsolidated, poorly sorted sand with very fine to very coarse grains. The productive interval consists of turbidite beds generally 2 to 5 ft thick that exhibit normal upward fining of grain size, and that usually are separated by thin, low-permeability diatomite beds. Average porosity is 27 percent and air permeability is 520 md under reservoir conditions. The over-all net-to-gross ratio for the zone is 0.74. The rock is saturated with a 14 deg. API oil whose viscosity is a strong function of temperature (Fig. 2). Current oil saturation in the main part of the reservoir is 59 percent but only 36 percent in the depleted portions near the top. JPT P. 1559

The Charco Redondo Thermal Recovery Pilot

A highly instrumented reservoir was steamflooded in 1965 to determine heat losses, formation heat content, location of formation and injected fluids with time, and residual oil saturation. Predicted heat losses were comparable with those determined from field data. The results of a subsequent successful effort to ignite this reservoir following the steamflood also are presented. Introduction Thermal recovery methods are used to improve production of heavy viscous crude oils. Steamflooding and production of heavy viscous crude oils. Steamflooding and fireflooding are two methods that have been used extensively throughout the industry. In either application, prediction of reservoir behavior is necessary so cost prediction of reservoir behavior is necessary so cost estimates can be made. In 1965 Bellaire Research Laboratories conducted a fully instrumented pilot steamflood in the Charco Redondo field, Zapata County, Tex. This pilot was followed by an in-situ combustion experiment pilot was followed by an in-situ combustion experiment in the same pattern early in 1966. The paper is divided into two parts. Phase 1 describes the steamflood, conducted to determine heat losses, location of injected fluids with time, and the residual oil saturations. Phase 2 describes the in-situ combustion experiment, conducted to determine if residual oil saturations following a steamflood were adequate to support combustion. Phase 1 - Steamflood Phase 1 - Steamflood Reservoir Properties Reservoir properties are itemized in Table 1. Pattern Pattern As shown in Fig. 1, a 1.01 ha (2.5 acre) isolated inverted five-spot pattern was selected. Injector 111 and Producers 112, 113, and 114 were drilled to complete the pattern Producers 112, 113, and 114 were drilled to complete the pattern in conjunction with existing Well 84. The sides of the square pattern were 100.6 m (330 ft). Producer and Injector Completions Producer and Injector Completions The producers were completed in 20-cm (77/8 in.) holes with 14-cm (51/2 in.) OD casing cemented in place with high-temperature cement. All were completed with slotted liners and canvas packers. Each contained 8.3-cm (2 7/8 in.) perforated tubing with a mud anchor and a high-temperature bottom-hole pump. Since the depths were shallow (Table 1), no special provisions were needed for casing expansion. The injector was completed with 18-cm (7 in.) OD casing set to the formation top using high-temperature cement. A 15-cm (6 in.) OD hole was drilled to 0.61 m (2 ft) below the formation bottom with a 14-cm (5 1/2 in.) OD slotted liner set to this depth. Open-end injection tubing 7.6 cm (3 in.) was positioned at the bottom of the interval. No packer was used and no special provisions were made for casing expansion other than a swivel connection at the surface where the steam line joined the tubing. Monitor Array and Completions Twenty-nine monitor wells were positioned in concentric rings around the injector, as shown in Fig. 1. The rings were located at radii of 15.2 (50 ft), 35.0 (115 ft), 50.3 (165 ft), and 65.1 m (220 ft) from Injector 111. The wells located on these rings were on four major azimuths drawn from the injector to the producers and on four intermediate azimuths. Cored locations are indicated in Fig. 1. JPT P. 1522

Analysis of a Steam Drive Project, Inglewood Field, California

This is the first reported California field data on the vertical extent and residual oil saturation of the steam swept zone. Field-derived data on reservoir heat distribution support the published theoretical data. Introduction The Inglewood field, discovered in 1924, occupies a faulted anticline along the Newport-Inglewood Fault System on the western edge of the Los Angeles basin (Fig. 1). The Upper Investment zone, UB sand, selected for this test is the shallowest producing reservoir in the field and lies about 1,000 ft below surface ( 650 subsea). The UB sand productive limit are defined by an updip sand pinchout, the Inglewood Fault, and by down-dip water. The UB sand is 40 to 60 ft thick, consists of fine- to coarse-grain sand with occasional pebbles, ranges from soft to unconsolidated, is overlain by a thick siltstone section and has bottom water. The reservoir properties are shown in Table 1, and electric log characteristics in Fig. 2. The air permeability ranges from 3.3 to 14.3 darcies in the top 40 ft of the reservoir, and porosity averages 39 percent. The primary producing mechanism is pressure depletion with primary producing mechanism is pressure depletion with water encroachment. Oil in place at start of project was 1,930 bbl/acre-ft. The Investment zone oil is asphalt base, 14 degrees API gravity with an in-situ viscosity of 1,200 cp. The high oil viscosity, low reservoir pressure, shallow depth and high oil saturation are all favorable for application of thermal recovery methods. Preliminary laboratory studies of steamflooding in Inglewood cores indicated that residual oil saturations of approximately 20 percent could be achieved with throughput of 1 PV of water converted to steam. Chevron Oil Field Research Co. and Standard Oil Co. of California, WOI conducted the Investment zone lost to learn if the low laboratory residual saturations could be obtained in the field and to determine the oil displacement efficiency in the project area. The test was designed to obtain data on vertical and areal coverage, heat losses, and rate of steam front advance, and to evaluate producing problems associated with continuous steam injection. Design Project Area Project Area Fig. 3 shows the steamflood pilot layout. It is an inverted six-spot containing 2.6 acres within the five first-line producing wells. The project area of the reservoir has essentially no dip. Injection Well 270 and Temperature Observation Wells 271, 272, 273 and 293, were newly drilled for the project. The location of Wells 304 and 304A, which were drilled specifically to obtain post-steam saturation, is also shown in Fig. 3. Well Completions The injection well was completed in only the top 40 ft of sand to avoid water and was perforated in a 30-ft interval 10 ft below the top of the sand. The four temperature observation wells were completed by cementing 3 1/2-in. tubing through the UB sand to surface. Observation Well 271 also was cored to establish presteam saturations in the pilot area. JPT P. 1141

Performance of Equipment Used in High-Pressure Steam Floods

Abstract The high temperature and pressures encountered in steam flooding have necessitated the use of premium and, in many cases, unique equipment. Field results from three steam flood installations give an insight as to the performance of high-pressure equipment when subjected to the accompanying high temperatures. Performance of the equipment and factors entering into the selection of equipment for steam flood installations are discussed. Introduction Recovery of low-gravity, high-viscosity crude oil from relatively shallow reservoirs is becoming feasible through the application of steam flooding. Pan American Petroleum Corp. initiated a pilot steam flood with a 5.36 million Btu/hour, 1,500-psi steam generator at the Winkleman Dome field in west central Wyoming in March, 1964. After one year of operation, this steamer was replaced with a larger unit capable of 12 million Btu/hour at 2,500 psi. Two other pilot steam flood projects were started at that time using 12 million Btu/hour, 2,500-psi steam generators, one at the Salt Creek Shannon field and another at the Fourbear field, both in Wyoming. This paper discusses the equipment used in high-pressure steam flooding and reviews some of the problems encountered in the application of the equipment. Where determined, a suggested solution is presented. The discussion follows the conventional flow of water and steam: water treating. steam generation, steam control and transmission, wellhead and subsurface equipment, and instruments and data collection (Fig. 1). The steam generation and transmission equipment discussed in this paper has been designed for 2,500-psi saturated steam service. Maximum operating conditions have been 1,875 psi and 626F. Water Treating Successful operation of steam generation equipment depends primarily upon a good source of water combined with an effective water treating system. Experience gained in the past two years of pilot steam flood operation indicates the majority of steamer down-time is caused by water treating problems. The quality of raw water dictates the amount of treating required; therefore, it is imperative that the best water available should be used. Some criteria for a good quality raw water are:the water should be free of oil or filming amines;dissolved gases such as O2, C2 and H2S, should be absent or at least present only in trace amounts;total hardness should be low; andsuspended solids concentration should be low. Since the quality requirements of water used in a single-pass steam generator are extremely stringent, it is unlikely that the available raw water can be used without some form of treatment. JPT P. 1525ˆ