Your account already exists. Please login first to continue managing your settings.
Beware of analogous fields – testing in a New Mexico field indicated that one field would not perform as well as its neighbors.
With a preponderance of mature wells and reservoirs in the US, it is essential to find ways to further enhance recovery and extend reservoir life. Many options are available, from redesigning artificial lift systems to novel stimulation techniques to adding reservoir energy; thus, selecting the appropriate application becomes important. The selection process begins with understanding existing reservoir and operating conditions. Is gas available to assist in lifting? Are clays present in the rock? Is reservoir pressure depleted?
A second component is to investigate best practices locally or on a regional and even national scale. A successful practice will be applied (or misapplied) rapidly. Dissemination of information also is very important in this step and is provided by a wide variety of professional organizations. A third item to consider is what new technology needs to advance or research accomplished to meet the goal of extending reservoir life and what information can be acquired cost-effectively.
In one case in New Mexico, there was potential for water-flooding in a shallow, small pressure-depleted oil reservoir not conducive to a fully developed, patterned waterflood. The target reservoir was thin and small in extent, shallow, at low pressure and temperature, and had unfavorable mobility ratios. Initial primary energy was not sufficient to produce the oil; however, significant mobile oil remained to be recovered. The hope was that adding energy by waterflooding would improve oil recovery and extend the life of this marginal reservoir.
The Round Tank field was selected because it provided an opportunity to extend waterflood development to reservoirs of limited size and unique reservoir conditions. Discovered in 1970, Round Tank produces from the Queen formation, a thin sand averaging 15 ft (4.6 m) in thickness. Most of the production is from the gas cap, with cumulative production to date of 4.2 Bcf. A thin oil column exists below a gas cap that contains more than 60% nitrogen. Two wells completed in the oil column have produced only 26,000 bbl of oil and no gas (i.e., 1% of the original oil in place). Original pressure was approximately 750 psi; current reservoir pressure is speculated to be approximately 100 psi.
As a result of the low pressure and temperature (75°F or 24?C), very low gas in solution, and high nitrogen content in the gas, the oil viscosity was high; therefore, the mobility ratio was unfavorable. All of these traits illustrate the complexity of successfully waterflooding a mature Queen sand reservoir.
The very low oil production in the Round Tank field ranks it as one of the least productive Queen oil fields. The higher the cumulative oil production, the greater the likelihood of a field being waterflooded, and vice versa. This confirms 1) the poor quality of the target, and 2) the success of waterflooding the Queen.
Two wells were drilled to initiate a pilot waterflood project. A core was acquired in one of the wells, and this, along with old logs (circa 1960s), 14 modern logs (obtained from wells drilled to the deeper San Andres formation), and production data were the only sources of information. Key findings were poor reservoir rock quality and the existence of a friable zone (one-third of the core was recovered in pieces). Petrographic analysis of the core (thin sections and SEM) exhibited significant fines and clays in the pore space along with anhydritic cement. Poor core injectivity tests confirmed the presence of fines migration. Evidence from sonic logs and the core samples indicated a friable zone exists with the Queen sand in the pilot area. Mechanical properties vary significantly within this reservoir.
The mechanical heterogeneity has significant implications for the success of stimulation (hydraulic fracturing) and water injection. The majority of Queen sand wells are hydraulically fractured to increase conductivity. Analysis of the fracture treatment in the new water injection well supported the creation of a horizontal fracture resulting from the shallow depth and the postulation that the compressible nature of the friable zone acted like a barrier, resulting in a high fracture gradient that diverted the horizontal fracture to a thin zone within the top of the Queen.
A 3-D-Blackoil simulation model was constructed with the limited field records. A successful history match was achieved after reducing the initial permeability values by approximately two-thirds. The large permeability reduction from history-matching indicates permeability of the Round Tank Queen formation is significantly lower than the other Queen sands since the original permeability was acquired from adjacent field correlations.
Field tests resulted in very poor injectivity into the injection well – a few barrels per day with high surface pressures. The simulation confirmed this behavior. This outcome is due to many factors, including low permeability, unfavorable mobility ratio, depleted gas cap, and unsuccessful fracture stimulation.
Even though NMT was unsuccessful in efforts to improve oil recovery and extend the life of the reservoir in the Round Tank Queen field, efforts provided several benefits to others with similar situations. First, improved reservoir description was accomplished with limited data – old neutron and sonic logs, 14 modern logs, and one core – and thus did not require high-cost information. Therefore, analogous fields could apply these concepts as well. Second, the importance of stimulation design cannot be overemphasized. In this case, the occurrence of a friable zone in a shallow reservoir increased the complexity of the stimulation.