CanArgo Energy Corporation gave an update on well testing operations at the Manavi 12 well in Georgia, which was drilled to appraise a new oil discovery in the Kura Basin.
Testing operations focused on a selected reservoir interval in the Upper Cretaceous carbonates which was acid fracture stimulated earlier in the year after the recovery of oil and gas to surface from previous testing. The results of the current test have identified a possible oil-water contact in the M12 well which indicates a potentially significant hydrocarbon column in the Manavi structure. Following the acid fracture stimulation of the M12 well, it was flow tested for two time periods, a clean-up period and a main flow test. The well flowed at an initial high rate of up to 3,900 barrels of fluids per day (bfpd) on a 10/64ths (4mm) choke.
On clean-up, the well was shut-in while a production string was installed in the well and testing resumed in mid-April. The main flow test was carried out over an extended test period of 12 days on a 15/64ths (6mm) choke size, during which time production appeared to stabilize at approximately 800 bfpd with the flowing well head pressure leveling off at 580 psi (39.5 atmospheres) prior to the well being shut-in for a pressure build-up survey. The well produced with a high water fraction and a maximum oil cut of approximately 7% and in addition, the well flowed gas at a maximum metered rate of 2.12 million standard cubic feet (60 thousand cubic meters) per day. In order to obtain information concerning fluid entry points to the well and the source of the excess water, the well was logged using a capacitance water holdup Production Logging Tool.
The PLT data obtained was interpreted by an independent petroleum engineering company in Texas, USA. This data indicates that the majority of the fluid is entering the wellbore from the lower part of the test interval (located between 15,354 feet and 15,581 feet (4,680 meters and 4,749 meters) Measured Depth within the uniform Upper Cretaceous carbonate section) with much of the water originating from a zone below the test interval. The production log shows the first entry of oil to the wellbore at 15,463 feet (4,713 meters) MD with the oil inflow increasing upwards towards the top of the test interval which is still some 443 feet (135 meters) below the top of the carbonate section penetrated by the well. On the basis of the PLT data, a potential oil-water contact is interpreted to exist at a depth of about 15,463 feet (4,713 meters) MD, however the contact may be deeper, but could be masked due to a strong flow of water from below travelling up behind the uncemented liner. This indicates a potential oil column at the M12 location of the order of 551 feet (168 meters). As M12 is located down dip on the structure compared to the M11z well, there is potential for an increased oil column at M11z of the order of 1,076 feet (328 meters) with this well still being down dip of the crest of the structure.
A pressure build-up survey was recorded with downhole reservoir pressure gauges installed. On extraction of these gauges, the pressure was bled down and the resulting slow pressure build-up has delayed any attempts to return the well to flow. This pressure response may be due to limited connectivity with the formation and any natural fracture network which may exist in these rocks such as that observed in outcrop in the South Caucasus area. With the PLT data indicating flow from below the base of the test interval, it is possible that the pumped acid was not contained within the test interval. The loss of acid to a larger wellbore area would have had a negative impact on the overall depth of the stimulation and the propagation of fractures away from the well and therefore reduced the chances of establishing better communication between the wellbore and the formation.