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Summary. This paper reports on an analysis that links expected reservoir performance with wellbore hydraulics. The dynamics of counterflow of the kill fluid and gas below the kill string can play a significant role in the expected behavior during a dynamic kill. The design concepts and techniques presented should be applicable to any well that requires the kill string to be run or snubbed into the well or one in which the string is a significant distance off bottom at the time of a blowout and cannot be lowered to bottom. Introduction Industry literature on the concept of a dynamic well kill describes introduction of a kill fluid to the flowing gas stream at or near the flow zone in the blowing well. In a workover operation on a sanded-up gas well with a hole in the tubing, however, it may become necessary to perform a dynamic kill at the point above the flow zone where the last sand bridge is washed out. Arco Oil and Gas Co. became interested in whether the dynamic-well-kill method could be used, when sand was being washed out of a gas well with a hole in the tubing, to maintain sufficient control of the well to prevent an underground blowout if the sand bridges did not extend to the production zone in the well. To study the principles involved, we selected an example well from a gas-recycling EOR project. Wells in this reservoir produce 40 API [0.825-g/cm3] -gravity oil with GOR's of 30,000 to 40,000 scf/bbl [5403 to 7205 std m3/m3]. The gas is separated and injected into the reservoir. The reservoir pressure is thus maintained at about 4,700 psi [32 407 kPa]. The reservoir and gas properties are known. The example well was completed with 2 7/8-in. [7.3-cm] tubing, as Fig. 1 shows. Table 1 lists this well's maximum flow potential (MFP). To explore the risks that could result from an underground blowout, we assumed that a hole in the 2 7/8-in. [7.3-cm] tubing existed at 250 ft [76 m] and that the exit pressure was constant at 150 psi [1034 kPa], which is about a 10-lbm/gal [1198-kg/m3] fracture gradient. The well was assumed to be sanded up, with the bottom of the last sand bridge above the flow zone. The workover procedure under consideration was to snub into the well with a 1 1/4-in. [3.175-cm] tubing string, wash the sand out of the tubing, and if necessary, dynamically kill the well with 9.5-lbm/gal [1138-kg/m3] NaCl. Because the last sand bridge was washed out during the cleaning operation, the well could be opened to its MFP of about 25 MMscf/D [708 × 103 std m3/d] and an underground blowout would occur through the hole in the 2 7/8-in. [7.3-cm] tubing. Flow rates of this magnitude could conceivably crater the ground below the snubbing unit. Therefore, this type of operation needed the potential to kill the well dynamically when the last sand bridge was washed out at various assumed depths above the flow zone. Assessment of Potential for a Dynamic Kill Lynch et al. described a method for analyzing circulating dynamic kills of a gas well with reservoir performance data, wellbore hydraulics, and a kill string near the wellbore flow zone. Wellbore-hydraulics performance curves (Fig. 2) are generated for different circulation rates of a given fluid and compared with the reservoir performance curve. Any wellbore-hydraulics curve for a given circulation rate that intersects or falls below the reservoir performance curve (Curve B) will reach a stable flow condition, with the fluid being gas lifted out of the well. The minimum circulation rate to achieve a dynamic kill has a performance curve that is totally above (not intersecting) the reservoir performance curve (Curve A). The same approach can be used to analyze the dynamic kill potential of a kill string at any position above the flow zone in a well. Fig. 1 is a schematic of the wellbore geometry used to model the dynamic kill with 1 1/4-in. [3.175-cm] tubing inside 2 7/8-in. [7.3-cm] tubing. A reservoir-simulation/wellbore-hydraulics computer program was based on Clark and Perkins' work. To calculate the wellbore hydraulics, a single-phase flow model was used in the 2 7/8-in. [7.3-cm] tubing below the 1 1/4-in. [3.175 tubing, and a two-phase flow model was used in the 1 1/4 × 2 7/8-in. [3.175 × 7.3-cm] annulus. The well production data in Table 1 and reservoir properties in Table 2 were entered into a reservoir-simulation computer program to determine the expected flow rate of gas that the reservoir would deliver at the bottom of the 2 7/8-in. [7.3-cm] tubing for a given pressure at the perforations. Fig. 3 and 4 show the calculated reservoir deliverability as a function of wellbore bottomhole pressure (BHP). Table 3 lists the flowing gas composition used. For purposes of determining hydraulics within the wellbore, gas viscosity and density were calculated as functions of temperature and pressure. The reservoir pressure is approximately 8.5 lbm/gal [1018 kg/m3] equivalent, so a 9.5-lbm/gal [1138-kg/m3] NaCl brine was selected as the kill fluid. The viscosity of the brine as a function of temperature was calculated. The example well was directionally drilled, which is typical for the area. Hydraulic-pressure drops are related to measured depths (MD's), but fluid beads are related to true vertical depths (TVD's). For the example well, the relationship between TVD and MD was included in the computer program to calculate the hydraulic pressure drops and fluid heads properly at any given MD. The following assumptions and simplifications were used in calculating the wellbore-hydraulics curves for different circulation rates and led to a conservative design. 1.The increased OD at the connection upsets on the 1 1/4-in. [3.175-cm] tubing was ignored. 2. All downhole completion equipment, such as gas-lift mandrels and subsurface safety valves, were assumed to have the same ID as the 2 7/8-in. [7.3-cm] tubing with no leakage. 3. Oil production was not associated with the gas when brine was being circulated to kill the well. 4. No friction reducer was added to the 9.5-lbm/gal [1.138-kg/m3] NaCl brine. 5.The 2 7/8-in. [7.3-cm] tubing was clear of sand bridges and other flow restrictions from the perforations to the bottom of the 1 1/4-in. [3.175-cm] kill string. 6.The reservoir pressure was 4,700 psi [32 407 kPa], and no gas had been produced from this sanded-up well in the preceding 2 years. 7.The maximum surface-working-pressure limit with the 1 1/4-in. [3.175-cm] workstring and snubbing-unit pump system was 10,000 psi [68 950 kPa]. 8.The change from single-phase gas flow to two-phase gas and brine flow occurred exactly at the end of the 1 1/4-in. [3.175-cm tubing. SPEDE P. 215⁁
Reclamation of processed drill cuttings provides environmentally acceptable construction material for roads and pads thus minimizing the need to excavate materials from surface gravel pits. Regulatory agency policy goals of reduction in surface disturbance of Arctic environments, reduction of waste, and recycling of a natural resource can be achieved. In order to adequately assess the compatibility of drill cuttings with the North Slope environment, information regarding the chemical composition of background soils is required. This paper reports on the work done by ARCO Alaska, Inc. to establish a primary database on the chemical composition of uncontaminated soils and gravels from various North Slope sites. Background samples have been analyzed by EPA Method 3050 techniques, and ranges for metals and salts have been accepted by the Alaska regulatory agencies. Additionally, development of a secondary elutriate test method based on EPA Method SW924 is described as it was applied to analysis of background materials and drill cuttings. The technique evaluates the leachability of chemical constituents from various types of monofill materials. Data are presented for materials excavated from several wells in the vicinity of the Prudhoe Bay Field. Processed and unprocessed drill cuttings are compared through analysis of the chemical constituents. Results indicate that the removal of clays and other fine particles through the water-based processing technique produces high grade construction material. The techniques described in this paper are broadly applicable throughout the Arctic. Establishment of a chemical background database for the North Slope of Alaska will assist in minimizing environmental effects of placement of excavated material. In addition, techniques for processing and analyzing materials recovered from drilling operations in Alaska may be applicable to other Arctic areas where exploratory or development drilling is occurring.
Thorough experimental studies were conducted to assess the effectiveness of a drag reducing agent (DRA) to increase the flow capacity of transfer line that supplies treated seawater to power water injectors in carbonate reservoirs and ensure it has no adverse impact on water wells injectivity. These studies included: compatibility tests, corrosion rate measurements, flow through tube tests, and coreflood experiments. Experimental results showed that the examined DRA is compatible with the currently used biocides in seawater. Corrosion tests implied that the DRA decreased the corrosivity of seawater by 50%. Flow through tube tests confirmed that the DRA reduced frictional (drag) pressure drop in the tube and increase the flow capacity. The DRA was found to be sensitive to shear where its effectiveness decreased with high shear due to polymer chains degradation. Permeability reduction was observed at higher DRA concentrations. However, degraded DRA gave less damage compared to a fresh batch. The extent of permeability damage increased in low permeability (tight) cores. The DRA caused an external damage on the face of the core, where it was removed by reversing flow direction. The examined treatments (polymer oxidizers) degraded the DRA and restored core permeability. This paper summarizes three successful field cases of this DRA in seawater injection systems. Injection rates of six wells increased up to 34% after the DRA injection in the Brent Alpha offshore field. Injection of a DRA, up to 80 ppm, increased the total volume of seawater injected by 65% in the Gyda oil field, Norway. The use of a DRA in the seawater system of the Galley offshore field resulted in re-pressurizing the reservoir and maintained oil production. Based on the obtained promised results and successful field cases, field application guidelines for using DRA seawater system were summarized. Introduction Drag reduction is defined as the increase in pumpability of a fluid caused by the addition of a small amount of an additive to the fluid.1 This additive is known as a drag reducing agent (DRA) which is a long-chained polymer with a very high molecular weight. DRA reduces the frictional pressure drop caused by turbulence in the pipeline. As a result, flow rate in the pipe can be increased at the same operating pressure, or reducing the operating pressure while maintaining the same flow rate. In addition, some of the booster pumps can be eliminated and results to reduce energy and operating costs along the pipeline system.2 Drag reduction is a near-wall phenomenon and DRA works only in turbulent flow. Drag reduction has a wide potential application within the oil industry because large pressure drop reductions can be achieved with a small concentration of DRA.3–5
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