Summary The development of rotary rock bits with jet nozzles required means of estimating pressure losses in the drilling fluid flowing throughout the well being drilled and through the associated equipment. The initial tabulations were based on Newtonian fluids. Subsequent authors developed descriptions of drilling fluids based on Bingham or power law non-Newtonian fluid models. Because optimum-hydraulics theories dictate that hydraulic horsepower, impact, or impact force must be maximized, we made the difficult decision to determine these pressure losses by actual tests. A total of 119 water-base drilling fluids were pumped through capillary tubes up to 2 in, in diameter and through six standard sizes of drillpipe tool joint combinations. Drilling fluids were flowed through jet bit nozzles and were flowed up two annulus-size combinations as well as an annulus with hole enlargements. The annular tests included cuttings, which aided in determining flow patterns. This paper includes development of friction factors and empirical corrections for current theories to model flow of highly non-Newtonian fluids more reasonably. Procedures and equations arc offered to help estimate pressure losses in a drilling operation, even with very limited fluid property information typical of our industry. Introduction Field tests of flocculants and other polymers added to water or clay water drilling fluids resulted in lower pump pressures and higher pump speeds than predicted with available tables. In some cases, these pressure reductions were dramatic and resulted in loss of rig time inspecting for equipment failure. Field pressure measurements showed that the pressure losses for actual muds were significantly different from those calculated by available methods. A laboratory test facility was constructed to measure the exact pressure losses for various types of drilling fluids in actual drillpipes and annuli. The initial concept was to develop more comprehensive tables for various types of muds in the range of pipes used. After initial tests it became apparent that the number of tables required would make their use unattractive. Because this work was to assist field personnel in calculating pressure losses so that hydraulics could be optimized, it had to be based on flow property measurements available in the field. The best available field data are often the Fann plastic-viscosity and yield point measurements based on the 600- and 300-rpm readings. Dodge and Metzner indicate that the powerlaw fluid model can be used to describe the flow of drilling fluid in pipes; therefore, these fluids were treated as power-law fluids with suitable corrections to be applied where required. Equipment Flow properties and pressure drop in pipes were measured by pumping the test fluids through 10 pipes ranging in ID from 0.187 to 3.826 in. and in annuli from 5.044 × 2.5 to 12.715 × 5.0 in. Nominal 20 in. welded pipe and six types of drillpipe were manifolded into the full-scale test system. This system included a 20-bbl mud tank, a 100-hp electrically driven centrifugal pump, and automatic diaphragm valves for flow and bypass controlled by the flowmeter. Flow rates were measured by )- to 500- and 0- to 50-gal/min flowmeters that demonstrated better than 0.25% full-scale accuracy. Differential pressure along the test sections was measured with 0- to 100-psi, 0- to 400-in. water, 0- to 100-in, water, and 0- to 20-in. water differential-pressure cells. An automatic continuous flow of city water from the cell to the pressure taps was maintained at a rate of about 20 cm /min to prevent mud from entering the test lines. JPT P. 1414^

This paper provides a field review of the Pikes Peak steam project, showing key performance indicators of cyclic steam stimulation (CSS) and steam drive in non-bottom water. To test development over relatively thin bottom water (less than 5 meters), various steam processes were field trialed. Field pilot results from vertical well CSS, dual horizontal well gravity drainage, and a combination of vertical injectors-horizontal well producer are presented for comparison. Based on field experience and numerical simulation input, CSS has been successfully conducted with economic steam-oil ratios (SOR) in areas with up to 4 meters of bottom water by injecting significantly larger steam slugs in what is termed a drive, block and drain process. In thicker bottom water, the ability to operate at constant pressure to prevent bottom water influx confers an advantage to the horizontal well approach. Followup field scale developments of some bottom water areas are described. Numerical simulation results indicate that pressuring up of a depleted steamflooded zone to be an optimum strategy for maximizing offset flank recovery. This is being implemented in the field by re-injecting produced vent gases. Introduction A very successful steam project is being operated at Pikes Peak, located in the Lloydminster heavy oil block straddling the provinces of Alberta and Saskatchewan (Fig. 1). The producing formation is a Waseca channel sand at an average depth and thickness of 500 and 15 m respectively. The oil is a heavy 12.4 °API crude with a solution GOR of 14.5 m3/m3 and a dead oil viscosity of 25000 mPa.s. A summary of reservoir rock and fluid properties is listed in Table 1. From the initial steam pilot in 1981, CSS has been utilized with subsequent conversion to pattern steam drive to target development of the Waseca structural highs with no bottom water (Fig. 2). The result has been highly successful, with current oil recoveries reaching 70%in the more mature steamflooded areas. A remaining challenge for the project is the development of thinner oil pay underlain by bottom water in the structural lows flanking the steamflooded pattern areas. The flanks are also at a higher pressure than the adjoining heated areas which are pressure depleted at a mature stage of steamflooding. Geological Setting The Pikes Peak steam project produces heavy oil from the Waseca Formation of the Lower Cretaceous Mannville Group. The project is located on an east-west structural high within an incised valley fill channel complex that trends north-south (Fig. 3). It consists of a generally fining upward sequence with clean homogeneous unconsolidated quartzose sand at the base and sand-shale interbeds on top. Locally there are calcite-cemented tight streaks in the interval. Oil saturation in the best part of the reservoir exceeds 90%. Porosity is usually in the mid to high thirties and permeability is in the 5 µm2 range. The structurally high central portion has the best reservoir. It has no bottom water and tends to have thicker basal homogeneous sand with over 20 m of pay. Development has now gone beyond the central portion and into the edge area. The reservoir in this area usually has thinner homogeneous sand and a thicker interbedded zone with some bottom water. A typical log for this area is shown in Fig. 4. A discussion of the reservoir geology was published by van Hulten1. Development History The Pikes Peak steam project is located in the western Canadian Heavy Oil Basin approximately 42 km east of the city of Lloydminster (Fig. 1). Since the field's discovery in 1970, and the initiation of steam injection in 1981, a number of papers2–5 has been published outlining the Pikes Peak performance and progress.

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This paper provides a field review of the Pikes Peak steam project, showing key performance indicators of cyclic steam stimulation (CSS) and steamdrive in non-bottomwater. To test development over relatively thin bottomwater (less than 5 m), various steam processes were given field trials. Field pilot results from vertical-well CSS, dual horizontal well gravity drainage, and a combination of vertical injectors/horizontal well producers are presented for comparison.Based on field experience and numerical simulation input, CSS has been conducted successfully with economic steam/oil ratios (SORs) in areas with up to 4 m of bottomwater by injecting significantly larger steam slugs in what is termed a drive, block, and drain process. In thicker bottomwater, the ability to operate at constant pressure to prevent bottomwater influx confers an advantage on the horizontal well approach. Follow-up field-scale developments of some bottomwater areas are described. Numerical simulation results indicate that pressuring up of a depleted steamflooded zone is an optimum strategy for maximizing offset flank recovery. This is being implemented in the field by reinjecting produced vent gases.

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