MANAVI

Cretaceous Exploration Potential

Historically, the main focus of oil and gas exploration in Georgia has been directed at the Middle Eocene sequence which provides the reservoir for the Samgori and Ninotsminda Fields. Although the potential of the underlying Cretaceous sequence has long been recognised from limited drilling, surface outcrop and by analogy to the Cretaceous in nearby Chechnya and Dagestan, where there has been very significant production from Cretaceous age reservoirs, this sequence remains very under explored. The Cretaceous is deeper; it was less well defined on Soviet era seismic data and technically more difficult to drill hence the general lack of exploration. As a result, the Cretaceous of the Kura Basin in Georgia has potential to contain very significant volumes of oil and gas reserves and CanArgo is fortunate to hold a significant acreage position in this very attractive play fairway.

The Upper Cretaceous stratigraphy typically comprises a chalk and chalky limestone sequence which is of the order of 1,000 feet (300 metres) thick. These rocks because of their brittle nature are generally fractured thus providing reservoirs with significant permeability. Such age rocks are prolific producers in the North Caucasus, and indeed worldwide. The carbonates are deposited on top of a thick pile of Cretaceous volcanic rocks which at outcrop are seen to be mainly pillow (submarine) lavas. Although not as good a reservoir as the carbonates, pillow lavas provide a ready–made fracture system in the shrinkage joints that separate the individual pillows of a massive lava flow. In the West Rustavi Field well #16 (within CanArgo's acreage) which reached a total depth in the Cretaceous penetrated a volcanic interval which flow tested water with gas at over 3,000 barrels per day thus demonstrating significant permeability.



Manavi Prospect

Following the acquisition and interpretation of new multi-channel 2D seismic data in the Ninotsminda, Manavi and West Rustavi Production Sharing Contract (Ninotsminda PSC) area in 1998 and 2000, CanArgo identified several large structures at the Cretaceous level, the largest of which is the Manavi prospect. Manavi is located approximately 28 miles (45 Km) to the east of Tbilisi and just to the east of the Ninotsminda Field and is mapped as a very large, east–west trending anticlinal feature at Top Cretaceous reservoir level, measuring approximately 12 miles by 4 miles (˜19 Km by ˜5 Km) with 2,950 feet (900 meters) of vertical relief. The prospect lies principally within the Ninotsminda (PSC) area, but part of the prospect extends into the adjacent Nazvrevi PSC area (also owned by CanArgo). All exploration costs in the Ninotsminda PSC area can be added to the cost recovery pool and recovered from the sale of oil produced from the Ninotsminda Field. CanArgo holds a 100% interest in both of these PSCs through wholly owned subsidiary companies.





Manavi Oil Discovery

The first exploration well, Manavi 11 (M11), drilled on the Manavi structure reached a total depth (TD) of 14,765 feet (4,500 meters) in the Cretaceous in September 2003. The well drilled by CanArgo Georgia using its own equipment encountered the Cretaceous limestone target at 14,265 feet (4,348 meters) with over 490 feet (150 meters) of hydrocarbons indicated on wireline logs and with no evidence of an oil-water contact present. On test the M11 well flowed light sweet oil at a visibly significant rate and at a high pressure prior to the test being terminated prematurely due to the mechanical failure of the casing, which was of API standard and pressure rated for the well, and the production tubing.



On the basis of the results of the M11 well and the seismic interpretation, Manavi has the potential to be a very substantial oil accumulation and as such is the first known Cretaceous oil discovery in Georgia. This exploration success opens up an entirely new play in the Kura Basin. In addition, the wireline logs and drilling data indicated the presence of further hydrocarbons in the shallower Middle Eocene sequence which is the productive sequence in the nearby Ninotsminda Field. This interval was not tested. Attempts to recover the damaged tubing from the M11 well were unsuccessful with only that part of the tubing down to the level of the crushed zone being extracted. The well was prepared and subsequently sidetracked as M11Z using slim-hole drilling technology due to the small size of the casing from which the well was exited.



The M11Z well reached a TD of 14,994 feet (4,570 meters) in the Cretaceous in October 2005 with the primary Cretaceous limestone target encountered at 14,032 feet (4,277 meters) some 230 feet (70 meters) higher than in the original M11 well. The entire carbonate section was penetrated which proved to be approximately 980 feet (˜300 meters) thick as expected. Drilling data and slim hole wireline logs indicated the presence of hydrocarbons in both the Cretaceous and Middle Eocene target zones, again no oil water contact was identified. As initial flow testing only produced small amounts of oil and gas, it quickly became apparent that the reservoir needs to be stimulated in order to properly complete the testing operation. Considering the small diameter of the hole which will limit the ability to optimally test this well, and the fact that the specialist equipment required for this job is both difficult to source and expensive to mobilise for a single operation, it was decided to delay completion of this test until after the completion of the planned M12 appraisal well.

M12 Appraisal Well

The M12 well is located approximately 1.25 miles (2 Km) to the west of the original discovery well. This well was drilled using a Saipem rig equipped with a top-drive drilling system and an oil based mud capability with Baker-Hughes International providing mud engineering services. Oil based mud was used in an attempt to control the swelling clays above the target horizon which had proved difficult to drill in the original well. A TD of 16,762 feet (5,109 metres) was reached in mid–December 2006 with a total thickness of 1,827 feet (557 metres) of Cretaceous carbonates and volcanics having been encountered. The significant hydrocarbon shows observed during the drilling process and the data obtained from wireline logs indicated a potentially significant hydrocarbon column in the well with no definitive presence of a hydrocarbon-water contact, but due to uncertainty over the fluid content of the lowermost section of the volcanics, it was decided to set a cement plug over the bottom 515 feet (157 metres) in the well.



Prior to testing, an 886 feet (270 metres) 5" pre-perforated production liner was run over the lower part of the potential carbonate reservoir interval and the underlying interbedded carbonate and volcanic units. The upper part of the carbonate interval (443 feet (135 metres)) remains isolated behind the 7” liner. During setting of the test string, the well began flowing and it was necessary to increase the mud weight to control the well whilst the test string and packer were set. Despite the flow and gas observed at surface during drilling operations, the initial testing operations resulted in a pressure increase at surface but with no discernable flow. Subsequent re-perforating of parts of the test interval resulted in minor flow with gas being flared and black 40.5° API oil collected at surface. It was considered that formation damage may have occurred, probably whilst controlling the well during the setting of the test string, with mud penetrating and blocking the formation.



It was concluded that stimulation techniques using acid to clean the well and create conductive pathways from the reservoir to the well-bore and hence bypass any reservoir damage would be required to fully production test the potential of the well. Acid stimulation is a fairly common procedure required to stimulate flow in carbonate reservoirs of the same age in the North Caucasus and indeed elsewhere. However, prior to going to the expense of mobilizing a full acid fracturing spread, such equipment being difficult to source and expensive to mobilise for a single operation, it was decided first to conduct a simple acid wash to ensure the effectiveness of acid stimulation under the reservoir conditions encountered in M12. FracTech Ltd., a UK company providing independent well completion and stimulation laboratory testing, design and consultancy services, and Schlumberger well completions experts provided advice on the chemicals and the stimulation program. The stimulation itself was performed through coiled tubing over a 564 foot (172 metres) interval consisting primarily of Cretaceous limestone where the best hydrocarbon shows were observed during drilling. On stimulation, involving a low pressure acid squeeze, the well flowed back unaided and produced liquids at rates of up to 46 barrels per hour (1,104 barrels per day) and a sizeable gas flare. Immediately prior to the treatment process, the wellhead pressure had increased to approximately 1,600 psig (110 bars). Over a 12 hour period, the well produced a total of 402 barrels of liquids consisting of pumped fluid and chemicals, polymer drilling mud released from the reservoir, oil and gas. The maximum oil cut observed was in excess of 50%.





The well, however, did not sustain flow, and it was concluded that the extent of the formation damage was beyond that which could be cleaned using a simple acid stimulation process, and as such a proper hydraulic fracturing of the formation with acid was required. The results of the initial treatment suggested that acid was the correct approach to opening this formation up to flow while at the same time proving the presence of oil in the reservoir.

Schlumberger was contracted to provide pumping equipment, chemicals and services to the Company for the acid fracturing treatment while the field operator replaced the 2 7/8 inch production string with a 5 inch fraccing string, and set a temporary plug to reduce the treatment interval, in order to give the operation the best chance of success. In late January, 2008 the acid fracturing stimulation was conducted using a multi-stage treatment comprising the pumping of a fracture initiating gel followed by hydrochloric acid stimulating fluids and diverter agents. This process was repeated a number of times for maximum efficiency. Approximately 2,700 barrels of treatment fluids were pumped at a maximum rate of up to 15 barrels per minute. An interval totaling 227 feet (69 metres) across the Cretaceous carbonate reservoir section in the well from 15,354 feet (4,680 metres) to 15,581 feet (4,749 metres) was isolated for the treatment. Pressure readings recorded during the operation indicate that fractures were successfully created.

Following the acid fracturing operation, the well 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 10/64^ths (4mm) choke. On clean-up, the well was shut-in while the frac string was replaced with a production string and testing resumed in mid-April. The main flow test was carried out over an extended test period of 12 days on a 15/64^ths (6mm) choke size, during which time production appeared to stabilize at approximately 800 bfpd with the flowing well head pressure levelling 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%; in addition, the well flowed gas at a maximum metered rate of 2.12 MMcf (60 MCM) 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 (“PLT”). 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 metres and 4,749 metres) Measured Depth (“MD”) within the uniform Upper Cretaceous carbonate section) with the zone below the temporary plug set in the well possibly stimulated. The production log shows the first entry of oil to the wellbore at 15,463 feet (4,713 metres) MD with the oil inflow increasing upwards towards the top of the test interval which is still some 443 feet (135 metres) 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 metres) 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 that there may be a potential oil column at the M12 location in the order of 551 feet (168 metres). As M12 is located down dip on the structure compared to the M11z well, we believe that there may be potential for an increased oil column at M11z in the order of 1,076 feet (328 metres) 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 possible 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.

A post frac evaluation is currently being undertaken which will incorporate the results of the acid fracturing, together with the flow, PLT, and pressure data collected during the stimulation and testing operations. This analysis will be used to investigate the effectiveness of the acid frac and the potential to shut off water within the currently contributing zones as well as options to recomplete the well higher in the Cretaceous carbonate interval and complete the testing operation. The results of the well testing operations to date appear to indicate a potential oil column of 551 feet (168 meters) at the M12 well, 435 feet (135 meters) of which is currently isolated by the 7" liner and remains to be tested. On completion of the technical study and availability of capital, it is planned to resume testing.

If commercial production can be established at M12, the well would be put into long-term test production and consideration would be given to performing a similar acid fracture stimulation of the M11z well which remains suspended.