Design of Micellar/Polymer System for a Wilmington Low-Gravity Oil
- Wayne R. Hause (Marathon Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1981
- Document Type
- Journal Paper
- 1,606 - 1,616
- 1981. Society of Petroleum Engineers
- 1.2.3 Rock properties, 2.4.3 Sand/Solids Control, 4.3.4 Scale, 5.4.1 Waterflooding, 5.1.2 Faults and Fracture Characterisation, 5.6.4 Drillstem/Well Testing, 5.2 Reservoir Fluid Dynamics, 5.2.1 Phase Behavior and PVT Measurements, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 1.6.9 Coring, Fishing, 5.3.2 Multiphase Flow
- 0 in the last 30 days
- 151 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
This paper describes the design of a micellar/polymer system to displace the heavy crude from a Wilmington Field, California, reservoir. Pattern design, transient testing, and the injectivity test are discussed also. The design problem was complicated by the unconsolidated nature of the reservoir rock. Initial design work was performed in sandpacks with available sand samples. After confirmation that a viable micellar/polymer solution could be designed, fresh cores were obtained. These cores were frozen at the wellsite and thawed only after placement in a laboratory core holder. System optimization work then was conducted. This work was complicated by some unusual problems.
The HXa subzone of the Upper Terminal of the Wilmington field produces a 35-cp (0.035-Pa.s) oil with an API gravity of 18 degrees (0.95 g/cm3). This is considered the heaviest oil for which a micellar/polymer process has been designed. A good system design requires extensive laboratory core flood testing using actual reservoir fluids and actual reservoir rock. The latter requirement was complicated by the fact that the upper terminal sand is unconsolidated. This paper describes problems and procedures used to overcome those problems in preparation for a test [approximately 10 acres (40 500 m2)] of Marathon Oil Co.'s Maraflood process in this field. The City of Long Beach operates this property with Long Beach Oil Development Co. as its sub-contractor. This project is cosponsored by the U.S. DOE. More details may be found in the first and second annual reports published by the U.S. DOE on this project and the pending third annual report.
Core Flooding Procedure
The core floods were conducted with a radial core flood apparatus designed at Marathon's Research Center in which actual reservoir core material was used. Fig. 1 shows how a reservoir core disk is flooded. The core holder was adapted to take a 5 1/2 in. (14-cm) diameter core. Flooding was from the center to the outer perimeter. Overburden pressures were maintained by axial loading. The Phase A core floods used available unconsolidated upper terminal and Ranger sand samples. The samples were (1) cold cleaned with a series of solvents, (2) vacuum dried and (3) packed into the core holder. The sand was
packed in synthetic produced water and then dried. It then was (1) saturated with the synthetic produced water, (2) flooded with reservoir oil to residual water and (3) flooded with water to residual oil. At this point, the micellar/polymer fluids were injected. The core floods were conducted in a constant-temperature bath maintained at the mean reservoir temperature of 125 degrees F (52 degrees C). Overburden pressure of 1,400 psi (9653 kPa) was maintained. Core pore volume and water permeability were determined during the water saturation phase of the operation. A constant-rate nonpulsating positive displacement pump was used to displace fluid. Each core was flooded with 1.5 PV of fluid from the center to the outer perimeter. Pressures were measured at the injection point and at the two locations across the top of the core as shown in Fig. 1. Produced fluids were collected and measured to determine oil recovery. Pressure data gave indication of the mobility control achieved in the core floods. The ring between the wellbore and the first tap includes 7.7% of the core pore volume. The first and second taps encompass the pore volume from 7.7% to 32.5%. The second tap to perimeter encompasses a pore volume from 32.5 to 100%. A reciprocal relative mobility was obtained by rearrangement of the Darcy radial flow equation for radial conditions.
|File Size||880 KB||Number of Pages||11|