Outcome could speed drilling plans across sector
Following a multitude of licence signing ceremonies in Baku, now is the time for some action. And BP will provide that, along with its Shah Deniz permit partners, when they extend the suspended SDX-1 well.
Most eyes of the other Azeri PSAs will be on that well also, for two good reasons:
The drilling semi Istiglal (ex-Shelf V) is virtually a new rig, and therefore the first real test of local construction yards working to western standards
Unlike AIOC's current work on the ACG fields, SDX-1 is entering little-known territory. Although the water is not deep, at 135 meters, this is a high pressure well in an unstable area. The result will give a strong indication to the other PSAs of what to expect when their time comes to drill.
The initial three-year Shah Deniz permit carries a commitment to drill two exploration wells, plus a mandatory third well if the partners apply for a further year's extension. An 800 sq km 3D seismic survey and seabed upper section site investigations have already been completed.
Water depths in the permit tail off from 50-60 meters at the top end to 600 m at the bottom. The Shah Deniz reservoir extends over an area of 10 x 20 km, with a prognosed depth varying from 5,000 to 7,000 m. Speaking
at the recent 'Caspian: Focus on Azerbaijan' event in London,
organized by IBC UK Conferences, Mike Shearman, president of BP Exploration (Shah Deniz), said "We believe the reservoir is segmented, with mud volcanoes near the crest. The seabed area is complex, not dissimilar to AIOC's, which limits the infrastructure that can go in."
In the past, Socar did drill two wells in to the structure, SD-6 and SD-4, but these did not penetrate the reservoir sands due to financial and technical problems. The new well, SDX-1, was spudded last July at a location north of SD-4, in an area perceived to be less technically complex, according to Shearman. The Dada Gorgud rig was used to drill the top hole section to 2,500 m, with 13 3/8-in. casing set before the well was capped off.
This exercise exceeded expectations, Shearman claimed, lasting 39 days against an anticipated 60. Estimated cost is $8million, more than $2 m below the budgeted figure, with no spillages or accidents reported. Non-productive time was just 13.5%.
However, the next 3,500 m of open hole in high pressure conditions required a higher spec unit than the Dada Gorgud. Shelf V, the available option, was almost new, having worked on just two wells since its completion in 1992. But major reconstruction was still required to bring it up to scratch for Shah Deniz.
"Apart from the steel superstructure, every piece of topsides had to be replaced, due to the nature of the wells," Shearman commented. On top of that, there was a time constraint to meet the terms of the PSA - "upgrading a rig in 18 months is a major challenge, even in the West. Here we had to build the shipyard as well". Revised columns and a totally new derrick had to be put in, but the rig did sail out last October, 18 months after entering the yard. It then underwent a few weeks of marine trials to test stability, in addition to tank tests, helicopter landing trials, plus a total recertification.
The re-named Istiglal was due to re-enter SDX-1 on December 1, a little behind schedule, as a state-of-the-art unit with complex systems that demanded substantial re-training of the drilling crews. "The last thing we want is to re-enter a well we had a lot of success on and then mess it up," Shearman said. Following initial clean-up of the top hole section, the target is to complete the new open hole section within 120 days of re-entry. Results of this well may determine the location of the second well, SDX-2, which should be drilled back-to-back. It could be a side-track. An extension of the PSA seems probable, as the partners are thinking of keeping both rigs in service through to 2002.
Absheron overviewAmong the more detailed presentations at the IBC conference was an update on the Absheron PSA, delivered by John Connor, Block Manager of Chevron Overseas Petroleum Azerbaijan. Chevron and partners Total and Socar are still in the geology/geophysics stage of exploration - they anticipate geologic similarities to Shah Deniz, 40 km to the west. Absheron is also 30 km south-west of AIOC's permit area.
A G&G study of the South Caspian Basin was initiated between Chevron and Socar scientists in 1993, which led to large scale processing and analysis of existing data over the next three years, mainly in California. One outcome, according to Connor, was the identification of the large D-2 structure - a large anticline favorably located in the Basin to trap migrating hydrocarbons. The team concluded that good quality, multiple reservoirs were present.
Following signing of the PSA in August 1997, preliminary work on the 400 sq km block started early in 1998, with the structure being re-named Absheron. The block lies in the northern part of the South Caspian Basin, in water depths varying from 300-700 meters.
An environmental impact assessment for the planned 3D seismic survey coincided with a preliminary environmental baseline sampling survey undertaken by the Svetlomor-2 geotechnical vessel. In addition to seabed and water samples taken across the block, core barrels were dropped last February into the mud volcano zone in the south-east of the block and also near the crest of the structure mapped from the earlier 2D seismic data. Gases analyzed from these cores look to be from considerable depths, thermogenic and from hydrocarbon-bearing rocks, Connor claimed.
Caspian Geophysical, the local joint venture between Western Geophysical and Socar, managed the 650 sq km 3D seismic survey between May and July 1998 using the M/V Baki. The South Caspian is one of the world's deepest basins, and one aim of the survey was to record data from the greatest depths possible below Absheron. To this end, two long record profiles were shot to a seismic recording time of 20 seconds (the limit of the vessel's equipment) in order to generate a picture of the basin down to 30 km.
Processing of that survey should be complete by now, with further analysis and interpretation to follow. " From what we've seen so far," Connor said, "Absheron is not such a tightly folded structure - it appears to be broader, hence there is the possibility of larger accumulations. We'll use 3D high resolution seismic for the shallow gas hazards in planning the drilling locations." Reservoirs within the productive series are expected to be present below depths of around 2km under the seabed.
The Absheron structure fills almost the entire block, and appears to be a relatively simple anticline. However, the new seismic is showing large parts of the structure to be affected by shallow gas, which complicates drilling preparations. The first well (not expected until 2000) will likely be in waters 500 m deep. Discussions are under way between Socar and other operators to convert a suitable semisubmersible.
"We want to use the seismic data to predict high pressure, through evidence of seismic velocity slowdowns at certain levels," Connor concluded. " We're also using seismic amplitude to predict the presence of fluids - obviously we want to distinguish between gas, water and oil. We believe there is up to 10% seismic anisotropy in the South Caspian basin. That's the difference between predicting the top of the reservoirs at 5 or 5 km."
Kur Dashi in effectOne of the most recently signed PSAs in the Azeri Caspian is Kur Dashi, which came into effect last July. The block is in the offshore extension of the Lower Kura Basin, a prolific hydrocarbon basin with numerous discoveries onshore, but little explored offshore (although hydrocarbon seepages from the sea floor have been recorded). Partners in the PSA, operated by Agip, are Mitsui, Reposl, Socar and Turkish Petroleum.
A paper delivered by Eros Agostinelli, Agip's resident manager in Azerbaijan, at the London conference stated that the block contains three known anticlines - Kur Dashi, Araz Daniz and Kirgan Daniz. Water depths range from a few meters, where the top of a mud volcano is present, to over 600 m. Targets are contained in the Pliocene productive series, the base of which ranges from just under 4,000 m to over 6,000 m below sea level. The main reservoirs lie in Pereryv, Balakhany and Surakhany sandstones, deposited in a fluvo-deltaic to marginal marine environment.
According to Agostinelli, hydrocarbon migration is likely to have begun in the Upper Pliocene, during or directly following the main tectonic phase which generated the structural traps. Vertical migration of hydrocarbons has probably been controlled by the mud volcanoes, which have acted as preferential pathways, he surmised.
New 3D seismic acquisition should have got under way in November. Agip is already negotiating with operators to build a new jack-up by 2000 for drilling in shallower waters - this would be the first rig built from scratch in Azerbaijan. Technically, Agostinelli added, Agip could be ready to drill by the middle of this year.
ACG full phase planning hit by falling oil priceDevelopment drilling on the Chirag-1 early oil project is ahead of schedule, with eight of the planned 24 wells completed. First oil exported via the northern pipeline route was lifted at Novorossiysk in Russia last March, and 70,000 b/d is currently being produced - still 35,000 b/d short of the platform's capacity.
According to AIOC president John Leggate, total costs of the facilities plus drilling/re-drills is estimated at $985 million, equivalent to a $2.38/bbl outlay. Once the western pipeline export route from Baku has been agreed, full field development can get under way with confidence. The plan is to achieve 300,000 b/d production by the second quarter of 2002 from the first ACG development phase. He added, The partners will eventually flow in $10-12 billion to recover 4.6 billion bbl and unknown quantities of gas from the three ACG fields.
For the full phase 1, the basic plan is for three platforms linked to a floater. However, given the prolongation of low oil prices, the development cost is turning out higher than AIOC would like, Leggate said. To get the cost base down, much of the development needs to be constructable locally, he suggested - AIOC's review options should become clearer this spring.
Commenting on the technology aspects of the full field development, Mike Crews, AIOC's VP Planning and Development, said that local geohazards and earthquakes were the biggest barrier - " nowhere else in the world do you find this combination in such density".
Among the technical achievements to date, he cited AIOC's 900 sq km 3-D survey in 1995 (the first such survey in the Caspian), which identified an amplitude anomaly running around the contour of the structure. The reservoir team's theory of oil/water contact along the rim was subsequently borne by the fourth well, he said.
Crews envisaged ocean bottom seismic being deployed to see through gaseous horizons, possibly even this year. AIOC was also working on whole core recovery, he added, using a special injection tool loaned by BP to recover the soft cores prevalent in this area.
For the drilling program, PDC bits and oil-based muds have been employed, with 730 meters in 24 hours being the best section achievement to date, using a steerable assembly. In regards to well completions, the chief objective has been high productivity with minimum sand production - to this end, Crews added, a number of techniques had been tried out. "Our best producer currently outputs over 20,000 b/d."
The ERD A-9 well may just have been spudded - the planned measured depth is 5,500 meters, including a near-horizontal section of 1,500 m. Multilateral wells are under review as a way of cutting back topside facilities and reducing drainage points required, said Crews; and splitter wells (two wells from the same conductor slot) are also likely on Chirag this year. Another concept under consideration, called " Rig and a half", involves use of a main drilling rig plus a hydraulic workover unit, as a way of simplifying topsides facilities and cutting waste. Cuttings reinjection is also on AIOC's agenda.
Despite the increasing complexity of each appraisal/development well, local Azeri back-up capability has not been found wanting, Crews commented. " Our best well to date was drilled and completed in 32 days - we've seen a tremendous improvement."
Copyright 1999 Oil & Gas Journal. All Rights Reserved.