Summary
The conventional way to produce an oil reservoir that has a gas cap is to produce only from the oil column while keeping the gas cap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gas cap and oil column. This methodology has application in reservoirs with a low-dip angle, large gas cap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. Geostatistical reservoir models are used to demonstrate that the gas cap recovery is minimally impacted by heterogeneities.
Introduction of the Concept
The conventional way to produce an oil reservoir that has a gas cap is to produce the oil column while minimizing production from the gas cap. During the pressure depletion of the reservoir, the gas cap will expand to provide pressure or energy support. After the oil column is depleted, the gas cap is "blown down."
In developing a production strategy for an oil reservoir with a large gas cap, a low-dip angle, and an available gas market, simultaneous waterflooding of the gas cap and oil column was evaluated. The water is injected at the gas-oil contact at rates high enough to overcome gravity effects and thus, the water displaces the gas up dip. In addition to providing pressure support, the created water wall separates the gas cap and the oil column regions. Since the development plan calls for the use of electrical submersible pumps (ESPs) in the oil producing wells, it is imperative to keep the gas production volumes from these oil wells at low levels so the ESPs will operate smoothly. As such, it is critical to control the downward migration of the gas cap. To maintain the reservoir pressure, water is injected not only at the gas-oil contact but also around the downdip periphery of the oil column to support the oil withdrawal rates.
A simplistic representation of the simulated structure is shown in Fig. 1. This figure shows the location of the gas-oil contact, along with the location of the water injector at the gas-oil contact and of the gas cap producer. The reservoir considered in this study has a dip angle of 2°. For the purposes of illustration the dip angle has been exaggerated in Fig. 1. The horizontal distance between the injector and producer is 12,155 feet. The structural elevation difference between these two wells is 425 feet. Taking into account the density difference between the water and gas, the injected water must overcome a gravity component of 149 psi in addition to the energy required for the water to displace the gas. The possibility of injecting water at high enough rates to overcome both the gravity and displacement components is shown in this paper.
The main objective of this paper is to present the concept of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact. The application of this concept for a newly discovered, offshore oil field has been studied. In this study, the majority of the effort was dedicated to theoretically proving this concept, as opposed to optimizing the number of wells and placement of wells to increase the recovery factors for oil and gas. This production methodology should be applicable to other reservoirs with similar characteristics.
Partial Proof of Concept
A literature survey indicated that the simultaneous production of the gas cap and oil column while injecting water at the gas-oil contact, has never been documented. However, four case histories were found in which water was injected at the gas-oil contact for the sole purpose of preventing the migration of the gas cap down structure. By preventing this migration, increased oil recoveries were realized. In these four cases, the gas cap was not produced during the depletion of the oil column.
One successful application of this production methodology was to the Adena field in the Denver basin in 1965.1 By injecting water at the gas-oil contact, the operator was able to keep the producing gas-oil ratio value close to the solution gas-oil ratio value for an extended time. The ultimate oil recovery was estimated to be 47% of the original oil in place.
The methodology of injecting water at the gas-oil contact was also applied in seven of the oil reservoirs of the Algyo Field in Hungary.2 These seven reservoirs are thin oil edge zones with large gas caps. The operators of this field were able to increase oil recovery by over 10% of original oil in place by using this methodology.
In the Canadian oil field Kaybob South, the injection of water at the gas-oil contact was studied by Deboni and Field.3 They used numerical simulation to determine that a waterflood can be successfully implemented adjacent to a gas cap if a proper water "fence" is established between the gas cap and oil column. The authors concluded that an additional 10% of the oil in place can be recovered.
Crude oil-utilizing strain Desulfovibrio vulgaris D107G3, a mesophilic sulfate-reducing bacterium isolated from Bach Ho gas-oil field in Vung Tau, Vietnam