Injection Tubing Research Articles

Near-Wellbore Placement of Small (Sand Consolidation) Treatments

Introduction The degree of success of small-volume, miscible near-wellbore treatments, such as chemical sand- consolidation systems, depends critically on the efficient placement of the chemicals. 1 In the case of sand consolidation, (1) failure to treat all the perforations, (2) contamination, or (3) dilution of the chemicals (which leads to a low-strength consolidation) will result in a continuation of sand production. 2 The final distribution of the injected fluids in the formation is a function of many complex processes occurring during placement: mixing in the injection tubing, stability of displacement, gravity-induced movement of the fluids, etc. In recent years significant effort has been directed to the study of fluid displacement (miscible and immiscible) in porous media. Stability criteria for the displacement of one fluid by another have been established, and the problem of viscous fingering-an unstable displacement resulting from a less viscous fluid displacing a more viscous fluid-has received much attention. Thus the stability of the displacement process is controlled by fluid mobility ratio, fluid density differences, formation porosity and permeability, and the fluid injection rate. The theory and laboratory evidence is well-documented for the linear low-rate flow associated with reservoir engineering studies. However, less attention has been given to the same displacement phenomena that occur in the near-wellbore region during small-volume chemical treatments (sand consolidation, acidization, selective plugging, etc.). Attention has been drawn to the need for more consideration of placement profiles in these operations. Experimental and theoretical studies have shown that gravity segregation between fluids of different densities in the well is an important factor affecting injection profiles. The experiments deserted in this paper examined the effect of fluid viscosity contrast and injection rates on the placement profile of the injected fluid in the near-wellbore region of the formation. These investigations were performed in both full- and reduced-scale models an although they were carried out mainly with sand- consolidation chemicals the results may be applied to other miscible, near-wellbore treatments. The work consisted of four distinct studies:experiments at low injection rates to study the stability of the displacement and simulate the phenomena occurring in the near-wellbore region during injection,a study of the rate of movement of fluids in the formation under the influence of gravity, which may occur in practice when fluid injection is complete and the well is shut in,experiments at high injection rates (equivalent to those employed in field operations) through single perforations, andmultiple perforation experiments at field injection rates to examine the effect of fluid viscosity ratio on the extent of pore fluid trapping between perforations. The information generated from these studies emphasized the placement advantages to be gained by improved mobility control (high viscosity contrast) and, more specifically, was used to estimate the effectiveness of sand-consolidation treatments in field operations. Experimental Models and Procedures Small-Scale Transparent Sector Model. A transparent model was used to observe the displacement of one fluid phase by another. The model (Fig. 1) consists of a sector (30 degrees) of a transparent cylinder, packed with crushed pyrex glass and saturated with a xylene/kerosene mixture. Axial pressures up to 0.6 MPa [87 psi] were exerted on the glass pack by hydraulically pressurized membranes mounted in the top and bottom covers. The xylene/kerosene composition was chosen so that its refractive index matched that of the crushed glass, thus making the pack completely transparent. The sector model had three inlets (simulated perforations) and three outlets opposite each other. A perforated plate covered by a wire mesh (74-um [74-micron]) screen was placed 0.10 m [0. 3 ft] in front of the outlets. This vertical screen prevented the formation of streamlines between the inlet and outlet during injection; thus, radial flow was achieved in the model. Experiments were carried out by injecting a nonreactive colored solution of known properties into the model and draining an equivalent volume of reservoir fluid. The position of the colored fluid then was monitored as a function of time. Physical Wellbore Model (PWM). The full-size PWM (Fig. 2) consists of a pressure vessel (diameter of 2 m [6.6 ft] and a height of 1.2 m [4 ft]) packed with sand. The sand can be stressed independently in axial and radial directions. Axial pressures up to 1.6 MPa [232 psi] can be exerted on the sandpack by two hydraulically pressurized membranes mounted in the top and the bottom covers. Radial stress is induced with the aid of 18 inflatable pressure cells placed circumferentially in the vessel. JPT P. 1905^

A Comprehensive Wellbore Steam/Water Flow Model for Steam Injection and Geothermal Applications

Abstract A comprehensive mathematical model was developed to simulate the downward or upward flow of a steam/water mixture in a well. Comparisons of model predictions with actual field data for both steam injection for oil recovery and geothermal production showed the validity of the model. The proposed model is based on mass and momentum balances in the wellbore and on heat balance in the wellbore and the surrounding media. Unlike the previous models, the pressure calculation accounts for slip and the prevailing flow regime, based on noted correlations. Furthermore, heat loss to the surrounding formations is treated rigorously. The overall heat transfer coefficient involved permits the consideration of a variety of well completions. The model was employed for a series of tests to evaluate the effects of the injection pressure, injection rate, time, and well completion on the downhole steam pressure and quality. It was found that the slip concept and the flow regime are essential elements in wellbore steam/water flow calculations. Pressure drop was found to increase with a decrease in the injection pressure, as also with more obvious parameters. An increase in the injection pressure or tubing size and/or a decrease in the injection rate led to a decrease in steam quality at a given depth.

Film Study on Wellbore Placement of Miscible Fluids

Introduction In a previous JPT paper we reported that gravity segregation of different-density fluids in the wellbore strongly affected placement profiles of sequentially injected fluids. That report was based on both experimental and theoretical studies of placement profiles involving immiscible fluids. A significant profiles involving immiscible fluids. A significant finding from the experimental study was that immiscible fluid placement is not affected by tubing tail position nor by injection rate, but by density differences only.In a new study reported here, we observed that miscible and immiscible fluid systems behave differently. Chiefly due to fluid mixing in the wellbore, miscible fluid placement profiles respond to both tubing tail position and injection rate. Hence, injection profiles may be controlled to some extent by proper choices of injection rate and tubing tail proper choices of injection rate and tubing tail position. position. We illustrate the new findings in this paper by applying them to miscible fluid placement problems previously modeled only approximately as equivalent previously modeled only approximately as equivalent immiscible cases. These applications suggest several additional approaches to solving common placement problems. A new 16-mm color film with narration problems. A new 16-mm color film with narration presents results of the current work and those from presents results of the current work and those from prior studies of immiscible fluid placement. prior studies of immiscible fluid placement. Experimental Observations We conducted six miscible fluid placement tests using the apparatus employed in the previous study, with minor modifications. The modifications included placing refractive index detectors to measure mixture placing refractive index detectors to measure mixture concentrations in the exit lines and metering valves to equalize flow through the three exit tubes. Isopropyl alcohol (sp. gr. 0.78 g/cm3) and a mixture (sp. gr. 0.92 g/cm3) of four parts diesel oil per part chlorothane were used as the two miscible fluids.The following observations are based on these and prior flow tests. prior flow tests. 1. Regardless of miscibility, gravity forces cause injected fluid to rise or fall through the in-wellbore fluid, depending on which fluid is heavier. If the two fluids are miscible, a mixing zone occurs at the discharge of the injection tubing. This zone grows as injection continues.2. For miscible systems, the growth and movement of the mixing zone depend on the injection rate, the injected/in-place fluid density ratio, and the tubing tail position relative to the perforations. In contrast, immiscible fluid systems produce a sharp fluid interface that rises or falls solely according to the density ratio and amount of fluid injected; the tubing tail position has no effect for immiscible systems. position has no effect for immiscible systems. 3. In miscible systems the interface between the mixing zone, with its constantly changing composition, and the in-place fluid reaches different perforations at different times; consequently, a perforations at different times; consequently, a different concentration of treatment fluid may be injected through each perforation. With thick intervals and small treatment volumes, some perforations may not receive any treatment fluid. perforations may not receive any treatment fluid. 4. Where a fluid is injected into a well filled with a heavier miscible fluid, injection rate and turbulence can cause the heavier rathole fluid to be displaced from the wellbore. Complete displacement depends on the rate and length of injection, the tubing tail position, and the depth of the rathole. For position, and the depth of the rathole. For immiscible systems, it is not possible to displace a rathole fluid during injection of a lighter fluid.5. Regardless of miscibility, when a heavier fluid is used to displace another fluid and the tubing tail is set at or below the top perforation, the fluid in the dead space above the top perforation cannot be displaced. JPT P. 1451

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

Waste Surveillance in Subsurface Disposal Projectsa

Waste Surveillance in Subsurface Disposal Projects^a

Silicate Foam Wellbore Insulation

When liquid sodium silicate boils, it forms a rigid foam on the heated surface. It is an effective and relatively inexpensive means of insulating steam-injection wells, and might also be useful for preventing paraffin deposition and hydrate formation. Introduction Thermally induced stress that causes casing failure has been a problem in oilfield steam-injection operations for a little more than a decade. Heat transfer in a well has been described analytically, and a number of methods have been devised to reduce wellbore heat losses so that lower casing temperatures can be maintained and higher steam qualities attained at the sand face of a reservoir. The methods include using insulated tubing, pumping a low-thermal-conductivity liquid into the annulus, and coating the tubing with aluminum paint. Insulated tubing is expensive and economics in many instances do not justify its use. Low-thermal-conductivity fluids when placed in a packed-off annulus and subjected to high temperatures packed-off annulus and subjected to high temperatures may gravity segregate, solidify, or become so viscous that the removal of a packer and injection tubing is often difficult. The primary draw-back to the use of aluminum-painted tubing is that it is difficult to prevent oil or other high-emissivity materials from prevent oil or other high-emissivity materials from clinging to its low-emissivity surface when it is being handled and lowered into the well. Such high-emissivity materials destroy its thermal effectiveness. A new insulating material is now available and a technique for its use in steam-injection wells has been developed. The insulating material, silicate foam, is formed by boiling a sodium silicate solution. The foam is an excellent insulator, having a thermal conductivity of approximately 0.017 Btu/hr-ft. degrees F. Fig. 1 is a photograph of the foam's structure. Its physical properties are given in Table 1. The Insulation Process In a field operation, a solution of sodium silicate is placed in a packed-off annulus, and then steam is placed in a packed-off annulus, and then steam is injected down the tubing. The hot tubing causes the silicate solution to boil, leaving a coating of insulating foam, usually about 1/4 to 1/2 in. thick, on the hot tubing surface. Since the foam immediately becomes an effective insulation, none is deposited on the inner wag of the casing. Silicate solution that remains in the annulus after steaming for several hours is removed from the annulus by displacing it with water (if the solution is not removed, it may solidify in the annulus). The water is removed by gas-lifting or swabbing. Fig. 2 is a schematic showing steps of the insulation process. Once the insulation is formed, heat loss is reduced and lower casing temperatures and higher sand-face steam qualities are the result. A comparison showing the foam's effectiveness is presented in Fig. 3, which illustrates the calculated maximum casing temperature in a well with packed-off tubing. The three cases show the relationship between casing temperature and steam-injection time for uninsulated tubing, commercially available insulated tubing, and tubing with a 1/4-in.-thick coating of silicate foam. The calculated casing temperatures are considerably lower for the insulated cases; however, there is not a great deal of difference between the two insulated cases. JPT P. 583

Results of a Tertiary Hot Waterflood in a Thin Sand Reservoir

Abstract This paper presents and discusses the results obtained daring a pilot test in the Loco field in southern Oklahoma. The test was conducted in a 2 1/2-acre pattern that was part of a 20-acre conventional waterflood pilot area. The conventional flood was well past its economic limit when the hot waterflood was initiated to obtain technical information from and operating experience in a reservoir containing 600 cp oil. Temperature data from nine observation wells showed that about 75 percent of the pattern was affected by heal, and that heat losses were severe in the pilot pattern. About 60 percent of the injected heat was lost to overburden and underburden zones during hot-water injection. Wellbore heat losses were held at tolerable levels at the shallow depth of the test by providing a low-pressure air annulus between the injection tubing and well casing. Hot water provided water injectivity increases of 200 to 400 percent. The hot water channeled across the lower portion of the oil sand in three directions through zones of relatively high water saturation. There was no conclusive evidence that natural fractures or pressure partings affected the flow of fluids in the pilot pattern; however response undoubtedly was affected by localized pressure and by injection-production rate ratios. The results snowed that hot waterflooding increased oil recovery. The total tertiary oil production from the pilot pattern area was 3,896 bbl or about 156 bbl/acre-ft swept by neat. The corresponding WOR was about 34:1. Description of the Hot Waterflood Process To hot waterflood an oil reservoir, water is injected that has been heated to a temperature substantially higher than the original reservoir temperature, but lower than the vaporization temperature of water at the prevailing pressures. In the reservoir the hot water flows continuously into cooler sand and rapidly loses heat to the sand until it has been cooled to the original reservoir temperature. Thus, a heated zone and a region or "bank" of cooled water begins to accumulate immediately after hot water injection is started. This bank of cooled water continues to grow ahead of the heated zone, which also grows, but at a slower rate. This occurs because heat transfer is almost instantaneous, and the ratio of heat capacities of water to rock is such that two or three unit PV of hot water must be injected to heat a given unit bulk volume of the reservoir. The primary displacement mechanism is the same for both hot and conventional cold waterfloods; i.e., "piston" displacement occurs at the original reservoir temperature. The incremental benefits of hot waterflooding usually occur long after the breakthrough of cold water at producing wells, and the increased oil recovery necessarily is accomplished with high WOR's (water-oil ratios). Heat decreases the viscosity and density of oil and water. These effects result in more rapid and increased recovery of secondary or tertiary oil. If the cost of the required heat is low enough, the ultimate oil recovery of a hot waterflood should be increased substantially over what would be expected at the economic limit of a conventional cold waterflood. The economic benefits of any hot-fluid injection project depend primarily upon the cost of the heat required to produce more oil at an increased rate. This cost depends in part upon the amount of heat lost to surrounding formations. Heat loss depends upon reservoir thickness, water injection rate and temperature, the depth of the formation. well spacing, and the characteristics of the reservoir rock and surrounding formations. In general, percentage heat losses decrease as injection rate and reservoir thickness increase. Although it is an old idea, hot-water injection has not received widespread field application in the oil industry as a drive process. Much of the original field work with hot water was done in Pennsylvania fields where water permeabilities and injection rates are low. In these cases, hot-water injection was used primarily as a means of increasing injectivities - not as a recovery process. Ramey recently has published an excellent review of the development of hot fluid injection processes. Recent publications and our own experiences now indicate that hot water or steam injection also can effectively increase the oil recovery from reservoirs containing viscous crudes. However, the economics of these methods as displacement processes have not been established. JPT P. 739ˆ

Use of an Insulating Fluid f or Casing Protection During Steam Injection

Abstract Laboratory and field experiments are described which define casing temperatures when high-temperature steam or hot water is injected down tubing with a particular well completion fluid in the tubing-casing annulus. Also discussed is the method used to place and contain this completion material. Field results observed following stimulation of a production well with 646F steam verified laboratory data that indicated thermal deterioration of one well completion fluid. Thermal deterioration in the 15-day field test was sufficient to destroy insulating properties of the fluid tested. By using an insulating fluid in the tubing-casing annulus casing damage can be prevented in wells not adequately completed for thermal stimulation treatments. Introduction High-pressure steam injection frequently causes casing failure in wells completed with J-55 short-thread casing. Failures generally are identified by joint pullout or fracture occurring as the wellbore cools after steam injection. Tensile failures are the result of casing deformation when temperature- generated compressive forces exceed the yield strength of the casing steel. Preventing casing damage in injection or production wells completed with J-55 ST and C, 8-rd casing requires reducing the casing temperature and/or the thermally induced compressive forces. There are many ways to reduce casing temperature while steam is injected down the tubing. A common method is to set injection tubing on a packer to isolate the casing from the injected fluid. This technique has been used successfully to protect casing when injection temperatures are 500F or less. Few failures have occurred under these conditions because resulting casing temperatures did not exceed the temperature at which casing steel yields when fully constrained. At tubing temperatures above 500F the low-pressure annulus is not positive protection against casing failure. This is shown in Fig. 1, which compares the relative failure risk for J-55 ST and C wells when steam at temperatures of 400 to 650F is injected down tubing set on a packer in 7-in. casing. The risk of failure is high as injection temperatures approach 650F. Several instances of casing failure have been observed under these conditions. The alternatives to a low-pressure annulus can be divided into two categories: mechanical insulation attached to the injection tubing, and an insulating fluid to fill the entire annulus between the tubing and the casing. This article discusses the use of an insulating fluid for casing protection.

Over-all Heat Transfer Coefficients in Steam And Hot Water Injection Wells

Abstract Casing temperatures and wellbore heat losses are critical variables in steam and hot water injection wells. Several papers have been written presenting methods of estimating these parameters if the over-all heat transfer coefficient is known. The over-all heat transfer coefficient for a wellbore is developed from its component terms to promote a better understanding of the concept. Specific methods have been selected from the heat transfer literature for estimating the size of each heat transfer component. Simplified calculation procedures are suggested for determining the over-all heat transfer coefficient. Comparison of calculated and measured casing temperatures during steam injection confirms the basic formulation and applicability of the suggested procedure for engineering calculations. Introduction The design of steam and hot water injection projects requires estimation of casing temperatures and wellbore heat loses. Several authors have shown that wellbore heat losses and casing temperatures can be calculated if the over-all heat transfer coefficient is known. This article discusses methods of determining the over-all heat transfer coefficient from the process variables. Development The steady-state rate of heat flow through a wellbore Q Btu/hour is proportional to the temperature difference between the fluid and the formation, and the cross-sectional area perpendicular to the direction of heat flow. The proportionally factor, called the over-all heat transfer coefficient, represents the net resistance of the flowing fluid, tubing, casing annulus, casing wall and cement sheath to the flow of heat. Thus, we can write Q = Uj Aj Tj............................ (1) Eq. 1 defines Uj, the over-all heat transfer coefficient based on the characteristic area A, and a characteristic temperature difference T,. Subscript j in Eq. 1 identifies the surface upon which these quantities are based. In theory, any radial surface could be used to determine the characteristic area. Some choices are more convenient to work with than others. For example, if hot fluid is injected down tubing it is preferred to let A, be the outside surface area of an incremental length of injection tubing, 2 to L, and let T, be the difference between the temperature of the flowing fluid Tj and the temperature at the cement-formation interface (the drill hole) Th. Then Uj = Uo, referring to the outside tubing surface area, and Eq. 1 would be Q = 2 to Uto (Tj- Th) L................ (2) If the fluid is injected down the casing or casing annulus. the characteristic area could be the inside surface area of the casing, and Eq. 1 would be written as Q = 2 ci Uci (Tj - Th) L..................(3) Subscript ci refers to the inside casing surface. An expression for the over-all heat transfer coefficient for any well completion can be found by considering the heat transfer mechanisms between the flowing fluid and the cement-formation inter-face. A brief derivation of the over-all heat transfer coefficient is presented in the following paragraphs for the case of a hot fluid flowing through tubing insulated with a dry air annulus. Other cases can be derived easily once the basic concepts are understood. Fig. 1 shows the wellbore model which will be used to derive Uto. Heat Transfer Mechanisms The rate of heat transfer between the flowing fluid and inside tubing wall is given by Eq. 4. Q = 2 ti hj (Tj - Tti) L...................(4) hf, is defined by Eq. 4 and is the film coefficient for heat transfer based on the inside surface area of the tubing (subscript ti) and the temperature difference between the flowing fluid and the inside tubing wall Tj-Tti. Heat flow through the tubing wall, casing wall and the cement sheath occurs by conduction. Fourier discovered that the rate of heat flow through a body is directly proportional to the temperature gradient in the medium. JPT P. 607ˆ