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Abstract This paper presents results from a multi-participant project conducted by AOSTRA, ARC and industry to improve rod pumping efficiency for thermal and non-thermal oil fields in Alberta. It describes experimental and theoretical investigations on the hydrodynamics of rod pump valves that resulted in improved valve design and increased field production rates; and shows that, two of the most frequent problems encountered in the field are associated with sand and gas/steam inflow and may be alleviated through a better design of pump valves. These problems were examined in the laboratory (ARC) by testing ball-valve hydrodynamics at different GOR and inclination angles. Nineteen different valve designs were investigated using two laboratory facilities. Visual observations regarding critical GOR and inclination angles and quantitative measurements of pressure drop at different pump rates and fluid viscosity were obtained. A diagram, in which measured drag coefficient was plotted versus Reynolds number, was used to capture the steady and unsteady behaviours of the cage-ball systems. This diagram provided a basis for improving valve design. Following discussions of the laboratory findings with the project participants (field operators and manufacturers), and at the instigation of one particular manufacturer, a new valve design (HIVAC) was completed, manufactured and field tested at numerous sites. The field test results showed a significant increase in flow compared to conventional API valves previously used at the same sites. Introduction The design and operation of sucker rod operated bottom hole oil pumps, used in 80 – 90% of artificial lift wells, reached a mature stage during the period 1970 – 1980.Improved diagnostic tools for evaluating their performance appeared during the 1980s. These tools included automated dynamometer cards that aided rapid and relatively inexpensive de-convolution and interpretation of load-stroke diagrams. During the last decade, the development of heavy oil reservoirs in Alberta, Saskatchewan, and Venezuela and the widespread use of horizontal and deviated wells for both conventional and heavy oil reservoirs has imposed additional constraints on sucker rod pump applications. In Alberta, thermal projects have always experienced difficulties with pumping operations. In 1988, a survey conducted by the Alberta Department of Energy-Oil Sands and Research Division (formerly AOSTRA) found that the most common problems encountered were pump seizure (customarily related to sand-laden fluids), and pump inefficiencies due to steam and non-condensible gases. A multi-disciplinary team consisting of ADOE-OSRD, ARC, eight major field operators and four rod pump manufacturers in Alberta was formed to address those problems. Although the major objective was to improve existing thermal pumping technology, more general applications to horizontal well and high gas/oil ratio situations were put at a high priority. An overview of the program and its major laboratory achievements during 1988 – 1991 has been discussed elsewhere. This paper describes further laboratory observations on valve hydrodynamics with conventional and slanted wells obtained during 1991 – 1992, as well as significant field results achieved using a novel valve design. Equation 1 (available in full paper)
Abstract The survival and growth of Alberta's bitumen industry during the continuing world oil price uncertainty will, to a large extent, depend on the development of improved technologies and enhanced cost effectiveness. It is first necessary to identify key parameters that impact production costs and to determine their relative cost sensitivities. Research can be focused on these targeted areas and production strategies can be developed which could potentially provide significant cost reductions. This paper describes how energy models developed at the Alberta Research Council are used to identify key areas and to determine their cost sensitivity. Current technologies for in situ extraction of bitumen from Alberta's deposits are reviewed, and the implications of different world oil price scenarios are analyzed. The economic impact of a number of promising operating strategies and processes are presented and analyzed. Introduction Five large bitumen and heavy oil deposits with resource estimated at 400 × 10 m of hydrocarbon are located in Alberta. Defined by UNITAR as a liquid hydrocarbon with a viscosity greater than 10 mPa •s and an API gravity less than 10 degrees, bitumen found in most of Alberta's reservoirs cannot be produced unless heated. There are various degrees of success of applying thermal recovery methods to Alberta's bitumen deposits — good results are reported in Cold Lake (Esso) and Peace River (Shell), while others are not that encouraging, especially in the Athabasca deposit. Even so, in the past five years, bitumen production increased six fold from less than 3400 m/D in 1983 to about 20,000 m/D in 1988. In the early years the production came largely from sizable piloting activity. In 1988, there were six commercial projects and 22 bitumen pilot projects operating in Alberta. Most of these projects were started during the 1983–85 era. Market opportunity, improved fiscal regimes and the high oil price prior to 1986 allowed this aggressive development. Since the precipitous price drop in 1986, the prevailing low oil price has put most new bitumen projects on hold. The bitumen production industry is at a crossroad. Its survival during the continuing world oil price uncertainty will, to a large extent, depend on the development of improved technologies and enhanced cost effectiveness. This paper analyzes the cost of bitumen production and uses a simplified Oil-Steam Ratio (OSR) model to evaluate a number of potential production strategies. A Liquid Fuel Model (ALF01), developed at the Alberta Research Council (ARC) is used to examine how, over the next 40 years, different oil price scenarios and improved technologies would impact on bitumen production. It is used to provide a basis for assessing the potential benefits of R&D in this area. Current In-Situ Commercial Technologies At normal reservoir temperature, bitumen is totally immobile. Mobilization of bitumen through the application of heat requires efficient convection and conduction of hot fluid into the formation. This involves a good distribution of heating sources and an increase of contact areas between the injected hot fluids and the reservoir.
Abstract A new sand control filter made of a pre-packed steel wool was designed to achieve a better control of solids influx for horizontal and vertical wells exposed to high-temperature recovery processes. An experimental laboratory study using Athabasca and Lloydminster formation samples was conducted in order to quantify the influence of filter depth and compression on the efficiency of the sand filtration-retention process and simulate a set-through completion. A model capable of predicting the amount of fines retained outside the filter, as well as those accumulated and produced during a standard flood process, is suggested on the basis of experimental data using Athabasca unconsolidated formation. The model is further used for assessing the influence of the design of a sand control device and the near-well formation characteristic in retaining fines during the production process. Introduction Controlling the production or sand in thermal and conventional unconsolidated oil fields is a critical component of engineering the well completion and production facilities, The high cost associated with well servicing and the considerable reduction of oil produced due to well sanding and plugging are among the most frequently encountered production problems. The frequent interruption of production associated with well servicing also disturbs the thermal process and may induce unpredictable formation damage. To alleviate problems related to sand production, new strategies are being continuously investigated. They focus on improving drilling operations, consolidating the near-well formation, and finding the most suitable well completion method including gravel and screens in combination with suitable adjustments of the rates of injected and produced fluids. Two distinct strategies have been suggested for sand control: total exclusion and partial exclusion of sand from the production system. It appears that each strategy has its own merits and drawbacks. If partial exclusion is adopted, efficient methods for eliminating the sand accumulated in the production system, including suitable artificial lifting devices, are still required; erosion reduces the life or production equipment considerably. It appears that a certain amount or sand production is beneficial to increasing the oil recovery, especially in the heavy and extra-heavy oil reservoirs where permeability and production increases are associated with moderate sand production. Total exclusion achieved through sand retention in the near-well region and in the filtration equipment will undoubtedly protect the production system from erosion, and reduce the risk of the near-well formation collapse. However, total exclusion could result in progressive plugging or the filter and deterioration of the productivity index. The most common methods of excluding sand utilize screening or a combination or screening and filter pack. They involve: slotted or screened liners; and packing of the hole with aggregate such as gravel. A basic requirement of these methods is to design the slots to retain the gravel which has been selected to hold the formation in place. Difficulties in properly placing the gravel (especially in horizontal wells), or in avoiding a rapid dissolution of gravel in a high-temperature and alkaline environment specific to steam operations, necessitated the use of slotted or screen liners with the opening designed to directly retain the formation.
Investigations And Field Observations On The Occurrence Of Flashing Phenomena During Sucker-Rod Pumping Of Hot Fluids From Thermal Processes
Coates, R. (Alberta Research Council, Oil Sands and Hydrocarbon Recovery) | Toma, P. (Alberta Research Council, Oil Sands and Hydrocarbon Recovery) | Lam, V. (Alberta Research Council, Oil Sands and Hydrocarbon Recovery) | Nguyen, D. (Esso Canada Resources Ltd.)
Abstract Flashing of high-temperature, near-saturation, aqueous oil emulsions and inflow of steam and volatiles produced during the thermo-recovery process of heavy oil are decreasing the efficiency of conventional sucker-rod pumping systems. This paper describes novel laboratory methods aiming to allow direct observations of this phenomena and assess the rationale and effectiveness of external speed control and better valve design to improve pumping efficiency. A 1:1 operational replica of a sucker-rod pump in which the pump barrel and valve cages have been constructed from Plexiglas, was used for laboratory simulations and room temperature visualization of effects induced by gas inflow and vapor flashing. Mixtures of Freon 114 and oil were used to simulate at room temperature flashing of high-temperature, high-pressure fluids, and a laser Doppler anemometer was used to measure the velocity within the pump. The presence of gas, either from inflow or by generation of vapor flashing resulted in a decrease of the pump efficiency. Visual observation of the occurrence of flashing within the pump could be directly related to regions of critical velocity peaks. The design of valves studied created image dimensional velocity fields with areas of high velocity reversing and stagnant flows, resulting in the flashing occurring at uneven intensities within the valve. The experimental rig and investigative methods developed offer a tool to assess pump operating strategies and designs for improving the pumping efficiency during adverse thermo-recovery conditions. Introduction The processes used for the recovery of hydrocarbons from oil sand and heavy oil reservoirs often results in the production of hot multiphase fluids. The current downhole artificial lift systems, which have been transferred from conventional operations, are not well adapted to pumping thermal, near saturation fluids. In certain situations a mixture of liquid oil emulsions, steam and non-condensable organic volatiles enters the pump and, as a result of local pressure and velocity distributions in the pump chambers and their oscillatory variation during the stroke, flashing of hot fluids occur. These situations can decrease the efficiency of a standard sucker-rod pumping system and can often lead to vapor lock and fluid pound conditions, equipment damage and drop of production rates. Additionally, production fluids are frequently laden with considerable solids that can cause costly shutdowns and well workovers. To improve the pumping process, a great need exists for assessing and understanding the effect of local velocity distributions to irreversible phase-change and solid-liquid-gas phase phenomena. New investigations methods are first assessed and then used for testing rationale equipment modifications and suitable operating strategies. This paper describes and assesses novel experimental apparatus aiming to allow direct observations and measurements of multiphase transport during the pumping process. The apparatus consists of a 1:1 operational sucker-rod pump in which the barrel and cages are made of Plexiglas allowing direct visualization of the flow within the pump. The following experimental procedures are assessed in a preliminary experimental program:—use of a laser Doppler anemometer to measure the velocity field within the pump, —use of a Freon-oil mixture to simulate high-temperature, high-pressure fluids and produce flashing induced perturbations at room temperature.
Solid Particle Impact Erosion Testing Of Texaco Filter Elements And Selected Well Completion Materials
Harris, P. (Alberta Research Council, Oil Sands and Hydrocarbon Recovery) | Toma, P. (Alberta Research Council, Oil Sands and Hydrocarbon Recovery) | Rabeeh, S. (Alberta Research Council, Oil Sands and Hydrocarbon Recovery) | King, R.W. (Esso Canada Resources Ltd.)
Abstract In-situ heavy oil, oil sand pilots, and conventional oil production located in unconsolidated sand reservoirs, have experienced a variety of problems related to plugging dissolution of silica sand conventionally used as a filter-pack, and erosion. The erosion is followed by a massive inflow of sand into the production wells resulting in reduction of flow capacity. To alleviate some of these problems, a new metallic filter of high porosity was designed and field tested. It employed steel wool elastically compressed arid sandwiched between inner and outer high-resistance mandrels. Field testing of the new filters has revealed some erosion-associated problems and a laboratory program was initialed to find the optimal design criteria for reducing the erosion damage. For the first time, the capacity of compressed metallic wool to withstand erosion was experimentally assessed. Standard sand-Jet blasting equipment was calibrated and used to determine penetration time for common well-material coupons and for compressed metallic wool filters. Filters having the compression factors ranging from 5 (density = 0.15) to 30 (density = 0.92) and metallic wool depth from 6 mm ro 19 mm were exposed to the erosion tests and results are presented graphically and analytically. It appears that increasing the wool density or filter thickness lead to an optimum value resulting in maximum filter erosion resistance. Photomicrographs of the eroded zones are presented in order to explain some of the mechanisms involved. Introduction In-situ recovery pilots and conventional oil production located in unconsolidated sand reservoirs have experienced a variety of problems related to filter-pack erosion and massive inflow of sand into production wells. As a result, considerable research sponsored by Texaco Canada Resources, was conducted at the Alberta Research Council, into new types of well completion, that would alleviate solids intrusion. To address the problems related to the dissolution or gravel packs in a high-temperature, high-pH environment and to improve flow conditions and skin-effect identified by excessive pressure drop in the wellbore region, a solids control device was developed by the Alberta Research Council and Texaco The Meshrite* filter employed steel wool sandwiched between inner and outer mandrels, designed to be part of the outer well casing directly in contact with the formation (Fig. 1). A field testing program in Athabasca, revealed difficulties associated with erosion of the filter by formation solids. The presence of high permeability zones in the vicinity or the production well resulted in preferentially high fluid-velocity streams. Entrained formation solids impacting the well, tend to erode holes through the downhole filter elements as illustrated in Figures 2, 3 and 4. As a result of these field tests, a research program was initiated in 1987 to study methods of assessing and improving the erosion resistance of the Meshrite filter and well completion materials such as 155 and N80 tubing and casing steels. The field filters constructed to date have used wool with a bulk density in the range of 0.6 g/cm (compression factor of 20) with a thickness of 9.5 mm.
- North America > United States > Montana > Western Canada Sedimentary Basin > Alberta Basin (0.93)
- North America > United States > Kentucky > Edmonton Field (0.93)
- Well Completion > Completion Installation and Operations (0.76)
- Well Completion > Completion Selection and Design > Completion materials (0.63)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (0.56)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.55)
Abstract A laboratory investigation into the recovery of bitumen using hot water and naphtha was carried out in 1981 and 1982 by the Alberta Research Council under contract of Texaco Canada Resources Ltd. An oil sand formation which was assumed to contain a highly permeable zone exposed to a hot water-naphtha injection was simulated in the laboratory using a Hassler type cell. The cell could accommodate a core 9.2 cm in diameter and 17.8 cm long. An axial, 13 mm diameter communication path was filled with frac sand, and hot water and naphtha flowed through at a known rate. The study presented in (his paper aims to offer a simple estimation of the economics of a hot water-naphtha process. Data collected from ten runs were processed in order to calculate the most characteristic parameters for the process. A multiple linear regression technique was applied to obtain simple linear equations subsequently used for the optimization study. An analogy between rates of production obtained in the physical simulator and those obtained in the field was heuristically assumed. This assumption permits the extension of the study to a field process. Within the limitations of the study the linear model approximated the real data and, as might be expected, recommended as high an injection temperature as possible regardless of the amount of naphtha added. Introduction Diluent naphtha and other light hydrocarbons are being considered as potential additives to stearn and hot water in order to enhance the in-situ recovery of bitumen from oil sand reservoirs. Insufficient information regarding the use of the naphtha as an additive in a hot water process required a dedicated laboratory study.A physical simulator was extensively used to provide information on the recovery process. Experimental An oil sand formation*, containing a highly permeable zone exposed to a hot water-naphtha injection was simulated in the laboratory using a pressurized Hassler-type cell as illustrated in Figure 1. The system consisted of a reconstituted core of surface-mined Athabasca oil sand contained within a deformable lead sleeve. The diameter of the core was 9.2 cm and the length was approximately 17.8 cm. An axial communication ath was constructed by drilling a 13 mm diameter hole and filling it with clean water-wet frac sand (10 – 20 mesh). A pressure vessel containing the oil sand sample simulated a 90 m overburden pressure through the use of nitrogen gas at 2.1 MPa. A constant injection rate of 3.0 kg/h of hot water and naphtha was used throughout the series of experiments. Differential pressure across the core was continuously recorded. The produced fluids, consisting of free bitumen, a bitumen-water emulsion and naphtha, were collected and analyzed. A back pressure control valve prevented flashing of the produced fluids. The flow rate was chosen as a compromise between realistic field data and the principal function of the laboratory facility, which was to rapidly screen a large number of variations on a particular recovery scheme.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)