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ABSTRACT Successes with steam injection as a means of increasing recovery from certain types of oil reservoirs have brought an entirely new line of equipment to the oil fields. This paper discusses operating principles and characteristics of equipment needed to carry out an oilfield steaming program, except for the steam generator. Water-treating and handling equipment, flow lines, well heads, down-hole tools, and accessory items are covered. INTRODUCTION Whether oil production is stimulated through the steam-soak (huff-and-puff) method or by well-to-well steam drive, there is more to the operation than just putting steam into the ground. Careful engineering of all phases of the operation is needed to avoid physical damage to surface equipment and injection wells, and chemical and mechanical damage to the reservoir Proper selection and application of equipment is one of the first steps in this careful engineering design, which covers the full range of operations from water treatment on the surface to injection of steam into the reservoir many feet underground. WATER TREATMENT Two major differences between industrials team boilers and oil-field steam generators dictate the differences in feed-water treatment, Fig 1. Conventional industrial steam systems usually operate oil a closed cycle in which steam used for turbine operation, heating of buildings, etc is returned to the holler for conversion to steam again Oil-field steamers operate on a "once-through" basis, where all steam generated is injected into the reservoir, and never recycled. Only a small amount of makeup water is needed to replace that which is accidentally lost from a conventional boiler system, or that which is used to "blow down" the boiler but feed water for an oil-field steam generator must be continuously replaced on a 100-percent basis. Cost of water treatment for a conventional boiler system, on a unit basis, is not too important because of the small number of 'units involved, but this same cost might be prohibitive in the oil fields. Conventional steam boilers take the steam to the dry saturated condition, or into the super-heat region, whereas oil-field steam is "wet" - generally about 80-percent quality (80-percent in the vapor phase, 20-percent in the liquid phase). The first of these differences is a disadvantage; the second is a distinct advantage The water-handling portion of a steam-injection system involves filtration, chemical treatment, storage, deaeration, conversion to steam, separation (optional), and metering (Fig 2) A description of equipment needed to treat feed water for oil-field steamers is impossible without some discussion of water-conditioning fundamentals, but no attempt will be made to cover the subject in detail as this has been clone adequately in recent publications Filters Feed water should be free of excessive suspended matter (non-ionic solids) to prevent contamination of subsequent treating equipment and plugging of parts of the system, including the sand face of the injection well Fig. 1 - Oil-field Steam-generating ProceduresRequire Unique Water-treatment (Available in full paper) Fig. 2 - Basic Components of a Steam-injection System, to the Well Head(Available in full paper)
Barge, David Lee (Chevron Corp.) | Carreras, Patricia Elva (Chevron ETC) | Uphold, Donald Dale (Chevron Corp.) | Al-Yami, Falah M. (Saudi Arabian Chevron) | Deemer, Arthur Ruch (Saudi Arabian Chevron) | Al-Anezi, Talal (Kuwait Gulf Oil Co)
Abstract The concept of steamflooding the Wafra Eocene dolomite reservoir originated in various studies conducted in the 1980's. In 1999, a comprehensive EOR study and Eocene huff-n-puff pilot suggested that steamflooding could be a viable recovery process for the reservoir. As a result of these studies, a staged development approach was incorporated to test the viability of pattern steamflooding the Eocene reservoir. The objective was to assess key technical challenges associated with steamflooding an anhydrite and gypsum rich carbonate reservoir. Additional challenges were the lack of fresh water available for steam generation, high concentrations of hydrogen sulfide gas, and higher reservoir pressures compared to most active steamfloods. The staged approach called for a single pattern steamflood test followed by a larger multi-pattern pilot. As a result of this strategy, a single pattern steamflood test was implemented in 2006. The design and initial performance of the small scale test (SST) single pattern steamflood pilot in the Wafra 1st Eocene reservoir are described in this paper. The pilot is comprised of one, 1.25 acre inverted five-spot pattern, consisting of four producing wells, a single injector and a single observation well. Continuous steam injection began in February 2006 at a rate of approximately 500 barrels per day cold water equivalent, 600 psig and a temperature of 489 ºF. The primary goals of the single pattern test were to test application of a mechanical seeded slurry evaporator to process produced water for steam generation and to assess steam injectivity into dolomite reservoirs containing gypsum and/or anhydrite. Injectivity assessment included evaluating reservoir response to steamflooding and investigating the variation over time due to rock/fluid interactions. Secondary objectives included analyzing well productivity and evaluating well testing equipment, facilities, and well construction. The SST has a comprehensive data collection and surveillance plan to support evaluation of these goals and objectives. The surveillance plan includes the collection of pre-flood and post-flood core data, frequent well testing for rates and fluid compositions, daily temperature recordings and periodic logging. After two years of operation, primary goals have been tested and exceeded expectations. A continuous thermal zone was developed in the 1st Eocene reservoir and steam breakthrough occurred at several of the producers. Generator feed quality water was produced at maximum throughput rate of 1,200 bwpd via mechanical seeded slurry evaporator equipment. Secondary objectives are currently being assessed with focus on current challenges of corrosion and scaling of producing wells.
Weak discovered, modified hot-lime process Steam for most oilfield steamflooding is acid cation vessels are then used to polish (MHLP) is a significant improvement over produced in conventional steam generators. A These generators are fired with natural is chelated with ethylenediaminetetraacetic Permian Basin produced oilfield water gas or waste heat and use a singlepass acid. Product water is supplied as feed to containing 2,000 ppm hardness, 500 ppm tube arrangement to produce 80-three waste-heat steam generators. Saturated steam (including Precipitate from the MHLS is thickened (TDS), and 200 ppm oil is being converted the 20% liquid phase) is injected into the in a "sludge" thickener to recover as successfully to steam-generator-quality oil formation with steam-injection wells. Alkali consumption and sludge Many impurities in the steam-generator Thickened sludge is then diluted with production have been reduced by 50% feedwater can be tolerated because the produced water and disposed of in deep compared with the conventional process.
A pilot steamdrive test has begun in the Marmul oil field in south Oman. It is intended that 1,774 U.S. tons/D [1610 Mg/d] of dry saturated steam will be injected into the test area for approximately 5 years to test the steamdrive process quantitatively. The surface facilities, consisting of a water treatment plant and steam generators, have been designed for reliable operation in the hot, remote desert environment.
Steamdrive is now a reality in the oil fields of the Sultanate of Oman. Plans for testing a variety of EOR techniques in Oman were Plans for testing a variety of EOR techniques in Oman were presented in Ref. 1. Steamdrive was one of the most promising methods presented in Ref. 1. Steamdrive was one of the most promising methods then proposed. This paper deals with the design, construction, and initial operation of a pilot steamdrive project in the Marmul heavy-oil field, south Oman. This is the first steamdrive project carried out in Oman and possibly in the Arabian Gulf. It is the first in a series of such developments planned for south Oman, where significant heavy-oil discoveries have been made during the last 5 years.
The Marmul field contains 2,453 x 10 bbl [390 x 10 m3] oil in place (21 to 23API [0.93 to 0.92 g/cm3]) with a viscosity ranging from 50 to 140 cp [50 to 140 mPa s]. This high oil viscosity causes an unfavorably high mobility ratio for waterdrive with the prospect of an ultimate recovery of about 20%. The prospect of an ultimate recovery of about 20%. The implementation of a steamdrive could significantly enhance oil recovery. The objective of this pilot is to test the steamdrive process quantitatively to enable direct extrapolation and optimization of a large-scale project and to verify reservoir simulation studies. A secondary objective is to gain experience with steamdrive in the harsh, remote environment of the south Oman desert.
The pilot calls for the injection of 1,774 U.S. tons/D [1610 Mg/d] dry saturated steam at 1,740-psi [12-MPa] wellhead pressure and 617F [325C] for 5 years. The test area consists of nine production wells and four injection wells in an inverted five-spot pattern production wells and four injection wells in an inverted five-spot pattern with a 696-ft [212-m] grid spacing (Fig. 1). It was recognized at an early stage that the relatively high injection pressure, the remote desert location, and the importance of a successful first trial demanded that special attention be given to all aspects of the project.
The facilities, which were commissioned during Sept. to Dec. 1984, are shown in Fig. 2. Untreated water is drawn from four water wells with submersible electric pumps and is delivered through a 6-in. [15. 24-cm] internally coated steel line to the water treatment plant. The water then passes directly through pressure sand filters plant. The water then passes directly through pressure sand filters and two stages of softening, and is collected in two 6,290-bbl [1000-m3] storage tanks. From these feedwater tanks, it is pumped through a steam deaeration vessel to five horizontal-tube oilfield steam generators, each with 443-U.S.-ton/D [402-Mg/d] steam capacity. One of these generators is always in maintenance or on standby so that effective capacity is 1,774 U.S. tons/D [1610 Mg/d]. The 70 to 80%-quality steam leaving each generator is passed through a separation vessel to remove unevaporated water that is discharged, after heat recovery and cooling, to a wastewater system. The dry saturated steam is distributed through an 8-in. [20.3-cm] header, about 0.6 miles [1 km] long, to the four injection wells in the nearby field. This header slopes continuously toward the wells, allowing a very high turndown without the risk of unstable two-phase flow resulting from condensate collection at low points.
Oil from the test area is collected in a dedicated oil-gathering station next to the steam facilities. The gas is then separated and compressed for burning as fuel in the steam generators. A test separator is used for regular three-phase testing of each well. Two 8,800-bbl [1400-m3] surge tanks provide at least 24 hours of residence time for emulsion-breaking chemical treatment should emulsion problems occur.
Two high-pressure reciprocating compressors provide a secure supply of sweet gas that is distributed to the steam-injection wells, where it is pressured into the annulus between the tubing and innermost casing. The injection tubing is insulated to reduce heat loss and to limit casing temperature. The continuous injection of gas into the annulus ensures that no water enters the annulus through the packer. This is important to prevent excessive heat transfer, either through-the water or by refluxing, to the casing, which could be overstressed at the high injection temperatures used.
Generating steam with an oilfield water containing a high concentration of total dissolved solids (TDS) was tested in the North Midway Field, Kern County, California. Conventional zeolite and weak acid cation exchange softeners were used for feedwater treatment, and steam was generated in a small scale oilfield boiler. Feedwaters with TDS concentrations up to 22,500 parts per million were successfully softened to "zero" parts per million were successfully softened to "zero" hardness levels and converted to 70% quality steam at 2300 psig. Results show that it is not necessary to have relatively fresh water for use in conventional oilfield steam generators. Furthermore, water treatment costs are economic.
Steam is produced in most oilfield generators by force circulating the feedwater through a system of watertubes heated by hot flue gases and radiant heat emissions. Depending on operating parameters, this usually results in a mixture of 70% steam and 30% hot water (by weight) at the generator outlet and discharges directly into an injection well. There is no mechanical separation of the steam and hot water mixture nor is the remaining hot water recirculated through the heater tube to be eventually converted to steam. Because "wet" steam is produced, the water quality requirements are much less stringent than for a conventional boiler.
Highly soluble sodium salts constitute most of the dissolved matter found in high TDS waters produced in western Kern County. They are tolerable produced in western Kern County. They are tolerable as feedwater constituents and can be concentrated in the hot water portion during steam generation. The solubility of these salts is quite high and increases with temperature as shown in Table 1. They should not cause serious scaling or corrosion as long as free oxygen and hardness are not present.
Treating for free oxygen is relatively straight forward and will not be discussed. However, hardness removal by conventional cation exchange softening is adversely affected by high concentrations of sodium salts in the feedwater.
Unpublished laboratory results indicate hardness leakage from a softener begins at TDS levels above 5,000 parts per million (ppm). At approximately 20,000 ppm, no hardness removal occurs with conventional softening. Any detectable hardness is undesirable in boiler feedwaters. This is primarily why high TDS waters have not been used in oilfield steam generators and relatively fresh waters are used.
Laboratory experiments run prior to the subject field test indicated that high TDS oilfield brines can be softened to "zero" hardness levels by using weak acid softening resins. The waters tested were similar to those produced in most California heavy oil fields.
Beginning in January 1978, a test was initiated to observe weak acid resin performance in the field and establish any adverse effects in a steam generator supplied with a softened high TDS feedwater. The test site was located in the North Midway Field, California (Figure 1). Feedwaters containing TDS concentrations ranging from 7,000 to 22,500 ppm and steam pressures from 500 to 2,300 psig (3,447 to 19,958 KPa) were utilized.
Some of the data generated during the field test are presented in this paper. The procedures used to soften the high TDS steam generator feedwater are provided including the results of softener and steam generator performance tests. Analysis of the steam generator heater coils, verifying that scale deposition and corrosion had not occurred, are discussed. Estimated water treatment chemical costs showing the use of a high TDS feedwater to be economically viable are also presented.
Since adequate water softening is an important consideration in using high TDS steam generator feedwaters, let us briefly discuss the principles involved.