Shifting The Focus To An Optimal Oil Recovery Strategy. Dr. John D.M. Belgrave, Belgrave Oil And Gas Corp. 13th International Oil And Gas Conference & Exhibition, Delhi, India...
On the Application of Horizontal Wells
in Air Injection EOR
Horizontal wells can be effective in air injection EOR applications and many such schemes have been implemented over a period of almost 20 years.
This article is intended to briefly describe the well configurations and philosophy of some meritorious air injection projects that have employed horizontal wells. Vertical injector-horizontal producer and horizontal injector-horizontal producer combinations have both been implemented.
An important observation with the use of horizontal wells is the potential difficulty in controlling the air injection or production profile along the lateral. Apart from being highly dependent on the geological framework, restrictions in the lateral can exacerbate any such issues.
We intend to update this page as information on other noteworthy projects becomes available.
From 1993 to 1998, Petro-Canada conducted an experimental project in the keg River C2C Pinnacle Reef pool in Alberta. This 37.3 oAPI oil pool had a single vertical producer and a weak water-drive that gave a recovery factor of 30% on primary.
Figure 1 - Skekilie top -down combustion. (Shekilie High Pressure Air Injection Pilot Project Progress Report No. 2, 1993)
The vertical producer was converted to an air injector by cementing-back most of the well interval across the pay section and a horizontal well was drilled at the original oil-water contact for production. Air injection was implemented as a top-down combustion process (see Figure 1).
The injection well was ignited and the combustion front was successfully propagated downward. An important addition to the knowledge base is that the injection well remained intact while the combustion zone progressed downward around it.
Although the horizontal well completely traversed the reef, only 60 m of the lateral section remained opened due to wellbore collapse that occurred during the well completion. This collapse was likely induced by fluid-loss into reservoir fractures.
A production test showed severe downward gas-coning into the restricted open section. However, there was a considerable (prorated) increase in the oil production rate. Also noteworthy was the absence of any chemical alteration of the oil or the formation of emulsions.
Pleito Creek (San Joaquin Basin, California)
A novel (Patent-Pending) top-down combustion project is that currently operated by Nimin Energy Corp. in California.
Nimin's Combined Miscible Process (CMD) uses foamed oxygen injection into the top of a heavy oil reservoir to generate CO2, heat and steam (Figure 2). The benefits of a CO2 flood, gravity drainage and steam injection are combined together to enhance oil projection.
CMD is expected to recover 35%-61% of the OOIP.
Mobil Canada operated the Battrum Field (containing 18 oAPI oil) in Southern Saskatchewan, Canada for 30 years using wet combustion. Initially the process used both vertical injectors and producers, and lateral displacement was the intention.
The high reservoir permeability (1-10 darcies) combined with the significant thickness of the reservoir (15m), led to gravity segregation of the injected air and water, and the formation of a secondary gas cap. High producing gas-oil ratios, water-cuts, and sand production resulted, with corresponding pump failures, corrosion and very stable emulsions.
In 1992 a horizontal well was drilled (Figure 3) to promote gravity drainage of the combustion displaced oil. This well produced sand-free. It also had substantially lower water-cuts and operating expenses, and 10 times the oil rate compare to the typical vertical well.
Little Beaver (Cedar Creek, N. & S. Dakota)
The Encore Acquisition Company's High Pressure Air Injection (HPAI) project at Little Beaver (Cedar Creek Anticline, U.S.A) was implemented as a tertiary process, i.e. after waterflood. The reservoir is a dolomite and contains 33 – 39 oAPI oil. The pool is situated on the crest of the anticline.
As shown in Figure 4, most of the injection and producing wells were both horizontal.
This project showed an early increase in oil production rate in response to air injection. Later, reservoir fractures near the crest of the anticline are believed to have caused channelling of the injected air and profile control issues in the laterals. There is a high probability that this problem could have been mitigated using wet combustion or cyclic air injection.
Figure 4 - Little Beaver Tertiary Air Injection Project.
(Encore Investor Presentation, 2006)
In 1994 Amoco Canada and the Alberta Department of Energy tested "Horizontal Well Cyclic Combustion" in a thin heavy oil sand in the Wabasca area, Alberta.
Although primary production with horizontal wells was economic in the 14 oAPI reservoir, the recovery factor was estimated to be only 5 – 10 % of the original oil in place.
The pilot design consisted of a central horizontal air injection well and two adjacent horizontal producers (see Figure 5).
The injector was first preheated with steam and then ignited (spontaneously) with air. Air was injected for 4 ½ months with the producers shut-in to pressurize the reservoir.
Once air injection was terminated, production was initiated in the producers. The production response was favourable and oil analyses did not show any upgrade or emulsion problems. There was also no oxygen breakthrough at the producers.