Bob Tippee
Managing Editor-
Economics and Exploration
Despite U.S. isolation efforts, Iran is asking international companies for financial and technical help with 11 large oil and gas projects.
Several of the projects would revive prerevolutionary ambitions to make economic use of gas reserves estimated at 740 tcf.
Plans of the 1970s to end flaring of associated gas by 1980 stalled after the Islamic revolution of 1978-79 and died in the 8 year war with Iraq that followed. Although domestic gas markets have grown, major reinjection and export plans foundered after the revolution, and much associated gas production, especially offshore, is still flared.
Since the end of the war with Iraq, National Iranian Oil Co. (NIOC) has had to rebuild heavily damaged oil production and processing facilities and spend heavily just to maintain production of crude. The state owned company now faces huge capital needs it cannot satisfy from oil sales alone, a fractured domestic political system with factions still violently opposed to non-Iranian influences, and an increasingly hostile U.S.
In a November conference in Tehran, NIOC gave foreign business representatives technical details for the slate of projects it hopes to advance with non-Iranian financial and technical help. The proposals, for what NIOC calls "buyback projects," provide an unusually thorough view of Iran's upstream and downstream petroleum industries.
Because of growing U.S. pressures, the number and identities of participants in the November conference haven't been disclosed. Sources present at the conference estimate 50-60 non-Iranians attended. They say conference topics were strictly technical.
U.S. pressures
The conference drew angry notice from Sen. Alfonse D'Amato (R-N.Y.), who sponsored legislation providing for financial retaliation against non-U.S. companies that conduct significant business in Iran. The administration of President Clinton imposed a general trade embargo on Iran last May.
The Senate passed the D'Amato initiative last December.
Also in December, the House of Representatives passed an intelligence spending bill with a provision, reported to have been conceived by Speaker Newt Gingrich (R-Ga.), for $20 million for covert Central Intelligence Agency operations aimed at changing the Iranian government. The Clinton administration supported the measure.
U.S. sponsors of those efforts accuse the Iranian government of disrupting Middle East peace efforts, supporting international terrorism, and trying to build a nuclear arsenal. The Iranian government denies the charges.
Tehran's parliament last month retaliated to passage of the intelligence spending measure by promising to execute three political prisoners accused of spying for the U.S.
So far, the U.S. has had to wage its anti-Iran campaign alone. The European Union has refused to honor the trade embargo and strongly opposed the secondary sanctions the U.S. Senate passed at yearend.
Whether or not that initiative becomes law, however, the U.S. stance increasingly forces international companies to choose between doing business with it and the international councils in which it wields strong influence, such as the United Nations and World Bank, and doing business with Iran.
Until that changes, chances remain slim that Iran will succeed in attracting much, if any, of the foreign capital it seeks for its oil and gas projects.
Still, the low key technical conference in November provided the most detailed look since the revolution at Iran's petroleum industry.
NIOC officials provided Oil & Gas Journal the technical information disclosed at that meeting. What follows is a project by project summary.
South Pars field
NIOC seeks international partners for the second and third of three planned phases of development of giant offshore South Pars gas/condensate field.
South Pars is an extension into Iranian territory of Qatar's North field. NIOC claims reserves of 100 tcf.
Each of the three phases of South Pars development is designed to produce 1 bscfd of gas from 20 wells.
NIOC expects the second and third phases each to involve two drilling platforms linked to a central production platform connected by pipeline to Assaluyeh, 97 km away.
Offshore processing would include gas dehydration and condensate dewatering. Production probably would be carried ashore as a gas/condensate mixture through a 32 in. pipeline, entering at 1,900 psi and arriving onshore at an estimated 1,515 psi.
Onshore facilities in NIOC's scheme would handle condensate stabilization, acid gas removal, dehydration, LPG recovery, and sulfur recovery. Some Phase 1 facilities could be used in the later phases.
Sales gas pressure will be about 1,450 psi.
First phase development is under way, similar in design to plans for later phases.
Outlet gas from the first phase will enter the Iranian transmission network at Kangan. Pentanes and heavier liquids, LPG, and sulfur in flake form are to be exported.
The first phase offshore complex comprises four platforms: a facilities and accommodation unit, central production facilities, a drilling platform, and a flare unit. A second drilling platform attaches to the complex as a satellite.
Gas and condensate are separated and treated offshore in the first phase and piped ashore independently.
Water depth at South Pars is 60-70 m. Top of the limestone/dolomite reservoir lies at 2,620 m subsea.
The reservoir has gross thickness of 400 m with net pay thickness of 197 m. Porosity is 10.2-12.6%, permeability-thickness 1,200-8,000 md-ft.
NIOC estimates reservoir extent at 2,600 sq km at the outer gas-water contact and 700 sq km at the inner gas-water contact. Gas saturation is 60-80%.
Reservoir fluid is 82.55 mol % methane, 5.29 mol % ethane, 1.96 mol % propane, 0.42 mol % isobutane, 0.71 mol % normal butane, 0.29 mol % each isopentane and normal pentane, and 2.57 mol % hexane and heavier. Concentration of nitrogen is 3.38 mol %, carbon dioxide 2 mol %, and hydrogen sulfide 0.54 mol %.
Separator condensate yield is 33-42 st-tk bbl/MMscf.
Salman-Dalan development
With international participation, NIOC hopes to develop nonassociated gas from the Permian Khuff reservoir, which it calls Dalan, underlying offshore Salman oil and gas field.
Salman is the Iranian extension of Abu Dhabi's Abu Al Bukhoosh field. Total-Abu Al Bukhoosh operates the Abu Dhabi side of the field. NIOC produces oil and gas from Salman field, formerly called Sassan.
NIOC claims that 70% of the Dalan reservoir lies in Iranian waters and estimates gas in place on its side at 6.4 tcf.
The company wants to produce 500 MMscfd from five Dalan wells at first, rising to 12 wells as flow rates decline during the 20 year reservoir life.
One well, 2SK-1, drilled from a four legged platform with three open conductors, awaits workover. Two satellite drilling platforms will have to be installed.
A production platform housing a manifold, inlet gas cooler, two train separation and dehydration facilities, condensate handling equipment, and vapor compressor would handle Dalan production. The condensate handling and compression facilities also would process associated Salman gas. A utility and accommodation platform for 60 workers also would be installed.
Condensate extracted at the Dalan production platform would flow to the existing Salman complex. Dry Dalan and Salman gas would be mixed and carried ashore under one of four options.
One involves direct transfer via a new 28 in., 208 km pipeline to Dubai's rapidly growing industrial port of Jebel Ali. Gas also might go to Jebel Ali by way of Iran's Sirri Island, 140 km east-northeast of the field and 115 km northwest of the port.
In another option, Salman-Dalan gas might flow through a new pipeline to Sirri Island for dehydration and sweetening and move 105 km from there to Qeshm Island.
Under still another scheme, the gas would go first to Lavan Island, 150 km from the field, and then 25 km to Bandar Mogham on the mainland, with or without treatment at Lavan Island.
Gas also could pass through Lavan and Bandar Mogham to processing facilities at Kangan, 172 km from Bandar Mogham.
NIOC says gas would enter pipelines in all cases at 1,300 psig and be delivered at about 500 psig, except for the Kangan option, under which delivery pressure is assumed to be 1,220 psig after compression at Lavan Island.
The Qeshm Island and Bandar Mogham destinations would require onshore facilities for receiving, acid gas removal, sulfur recovery, and dehydration, plus utilities and support equipment.
Balal field
The Balal field project would involve development of a 1967 discovery by Lavan Petroleum Co. (Lapco), a combine of Atlantic Richfield Co., Murphy Oil Corp., Sun Oil Co., and Union Oil Co. of California. The field was originally named Bahram.
Lapco planned to develop the field and had laid a 14 in. pipeline to Lavan Island, 98 km to the northeast.
NIOC estimates field reserves at 117 million st-tk bbl in the Arab/Hith formation and 17 million st-tk bbl in the Khatia formation.
Development would involve drilling of five wells, which would produce at a total target rate of 40,000 b/d for 4 years and at a declining rate for 11 more years. NIOC says gas lift or electric submersible pumps (ESPs) would be required, along with water injection of perhaps 50,000 b/d.
Subject to further engineering work, a development program might involve a 12-16 slot drilling platform from which the production and water injection wells would be drilled, a production platform, a tripod flare platform, and an accommodation platform for 60 workers.
After single-stage separation on the platform, oil would move to Lavan Island through the pipeline already in place. Final processing would occur in facilities now handling oil from Salman, Reshadat (formerly Rostam), and Resalat (formerly Rakhsh) fields.
The Khatia formation holds 29.4 gravity oil with viscosity of 3.6 cp and solution GOR (flash calculation) of 50 scf/st-tk bbl. Reservoir pressure is 1,651 psig, bubble point pressure 1,000 psia at reservoir temperature, 134 F. Crude oil volume factor is 1.1 reservoir bbl/st-tk bbl.
The formation NIOC designates Arab/Hith holds 41.6 gravity crude with solution GOR (flash calculation) of 412 scf/st-tk bbl. Volume factor is 1.262 reservoir bbl/st-tk bbl.
Reservoir pressure is 2,823 psig, temperature 174 F. Bubble point pressure at reservoir temperature is 1,180 psia.
Two Balal wells have been tested. The SW-1 flowed 5,376 b/d from Arab-Hith at 5,502-5,871 ft with 395 psi wellhead pressure and 5,745 b/d with 405 psi wellhead pressure after acid treatment.
From Khatia pay at 3,255-3,372 ft, the 3W-1 flowed 2,280 b/d of oil with 0.5% water cut after acid treatment at wellhead pressure of 92 psi.
The SW-2 well produced 7,680 b/d of oil from Arab pay at 5,582-5,810 ft after acid treatment at a wellhead pressure of 770 psi. The Khatia at 3,338-3,520 ft in SW-2 produced 3,408 b/d on test after acid treatment at a wellhead pressure of 72 psi.
Soroosh field
Farther north, NIOC hopes to refurbish and resume production from an offshore field shut-in since Iran's war with Iraq.
Soroosh field, in 150 ft of water 80 km west-southwest of Kharg Island, produced 86.3 million bbl of crude during 1967-79. It was shut in when a storage barge moved into dry dock.
Most production facilities, heavily damaged in the war, require replacement or refurbishment.
With international involvement, NIOC wants to restart the field and eventually produce 60,000 b/d.
The field has 14 wells. They produced 19 gravity, low GOR crude via ESPs from two zones of the Burgan sandstone found at depths between 6,710 ft and 7,500 ft subsea. A third Burgan zone in the field holds very heavy crude.
The original production scheme involved satellite production equipment linked to a main production platform, which handled gas separation. Crude moved from there through a 16 in. pipeline to the Pazargad storage barge for final desalting and storage.
Crude moved from the barge via 20 in. pipeline to a multibuoy mooring system for loading aboard tankers.
The project NIOC envisions includes inspection and refurbishment of eight, three- and four-legged well protector platforms and of the six pile production platform. Also needing inspection and repair are five subsea flow lines between satellite wells and the main production platform and a 16 in. subsea pipeline between the production platform and barge.
A tanker with 2.4 million bbl crude oil storage capacity would have to be converted into a 60,000 b/d floating production, storage, and offloading (FPSO) vessel with accommodation facilities.
The FPSO would be permanently moored with a bow turret mooring system connected by an existing subsea pipeline to a production manifold on the six pile platform. The system could load tankers as large as 240,000 dwt.
The FPSO would house facilities for oil and gas separation, desalting, flaring, and metering.
NIOC plans include a new four pile platform with power generation and distribution systems bridge-linked to the six pile production platform.
Two new well protector platforms and five new subsea flow lines would be needed, as well as submarine cables to the new platforms and existing platforms requiring ESPs.
Seven existing wells with ESPs require workover for installation of replacement pumps. Two existing natural flow wells also require workover and ESPs.
NIOC's scheme calls for drilling five wells, two of them directional from existing platforms and three from new platforms. Drilling would require a cantilever jack up rig.
Soroosh crude has viscosity of 93 cp at 130 F. with a GOR of 397 scf/st-tk bbl. The reservoir has pressure of 3,650 psia and temperature of 181 F.
Dorood gas injection
Another production project would use associated gas now flared in offshore fields near Kharg Island for injection in Dorood field, which lies under the island.
Subject to results of miscibility studies, NIOC estimates that injection of 400 MMscfd of gas could boost ultimate oil recovery from Dorood field by 200-600 million bbl. The project also would boost liquid recoveries at existing and new facilities.
Associated gas for the project would come from Aboozar, Foroozan, Nowrooz, and Dorood fields.
NIOC is revising a reservoir simulation study for Dorood field and will conduct a feasibility study before opening the project to international bidding. It assumes the project would take 4 years to complete.
Related to the planned Dorood gas injection scheme is a project under way to expand the Kharg Chemical Co. (Khemco) plant on Kharg Island and add methanol to its product slate. The plant now has design capacities to process 150 MMscfd of gas feed and recover 3,800 b/d of propane, 2,200 b/d of butane, 1,000 b/d of heavier liquids, and 600 tons/day of sulfur.
The plant currently processes 120 MMscfd of associated gas, mostly from Dorood field, and produces 2,700 b/d of propane, 1,900 b/d of butane, 3,100 b/d of heavier liquids, and 422 tons/day of sulfur.
After expansion, the plant will be able to process 200 MMscfd of rich gas and produce 4,600 b/d of propane, 3,200 b/d of butane, 5,100 b/d of heavier liquids, and 700 tons/day of sulfur. It also would yield 70 MMscfd of feed for a methanol plant.
Dorood oil and gas production comes from 10 onshore and 10 offshore wells. The field has no offshore production facilities, so production from the offshore wells flows through gathering lines to one of two production plants onshore.
One of these plants has design capacity of 100,000 b/d. The other has capacity of 123,000 b/d.
The project NIOC proposes would increase capacities of both Dorood plants. Gas injection wells would be drilled onshore and off, which would require installation of an undetermined number of platforms in 150 ft of water.
Additions to onshore Dorood facilities would include gas gathering and condensate recovery systems, a compression package, and additional utilities. New housing facilities also would be needed.
Under NIOC's plan, the expanded Khemco plant and condensate recovery system would receive a total of 480 MMscfd divided like this: 400 MMscfd from Dorood, 40 MMscfd from Foroozan, 25 MMscfd from Aboozar, and 15 MMscfd from Nowrooz fields. The chemical plant and condensate recovery system each would yield about 200 MMscfd of lean gas for compression and injection in the Dorood reservoir.
The condensate recovery system would produce about 5,000 b/d of liquids.
Offshore fields
Foroozan field produces from 47 wells through two production platforms. After gas is separated offshore, crude moves about 100 km northeast to Kharg Island through a 20 in. pipeline for processing at a plant with design capacity of 180,000 b/d.
Most of the crude is sweet, but a few wells produce sour crude. Foroozan's onshore facilities include equipment for two stage separation, hydrogen sulfide separation, and desalting. Khemco receives low pressure gases from the facilities.
NIOC wants to add a platform in 150 ft of water next to the main Foroozan production complex to house gas gathering and compression equipment, as well as additional utilities. It also wants to study two phase shipment of the field's production through the oil line.
Foroozan's onshore facilities would be expanded in line with increased gas flows, which after processing will go to the condensate recovery system.
Aboozar field, 75 km northwest of Kharg Island, produces sour crude from 66 wells through three identical production platforms. Gas is separated in a single stage process. Crude moves to Kharg through a 24 in. flow line.
Onshore Aboozar facilities include two identical streams for final separation, hydrogen sulfide stripping, and desalting. Resulting gases go to Khemco. Design capacity of the Aboozar production plant is 200,000 b/d.
NIOC wants to add a platform next to Aboozar's main production complex for gas gathering and compression systems. Two marine pipelines would be laid between satellite production platforms and the new platform. Also needed would be a gas pipeline to Kharg Island and modifications to onshore facilities to handle the additional gas, which would enter the condensate recovery system.
Nowrooz field, 30 km north of Aboozar field, produces mostly sweet crude. A central production platform separates gas from crude, which moves through an 18 in. flow line to a a processing center on the Iranian mainland, where capacity for Nowrooz crude is 60,000 b/d.
NIOC's proposal calls for laying a pipeline to carry Nowrooz associated gas to the Aboozar production platform for compression and entry into the pipeline to Kharg Island.
AMAK gas projects
A series of projects NIOC calls AMAK would compress and treat 220 MMscfd of associated Bangestan formation sour gas now flared at production facilities of five onshore oil fields around Ahwaz in Southwest Iran.
The projects would yield 160 MMscfd of lean natural gas after recovery of 21,000 b/d of NGL in two existing plants. Output would include 180 metric tons/day of sulfur at the Razi chemical complex, which produces ammonia, urea, sulfur, sufuric acid, phosphoric acid, monoammonium phosphate, and diammonium phosphate at Bandar Imam Khomeini.
AMAK projects would include installation of seven electrically driven gas compressor and dehydration stations at the Ahwaz-1, Ahwaz-2, Ah-waz-3, Kupal, Marun, Mansuri, and Ab-Teymour production units. They would require 180 km of 6-18 in. pipeline and 65 km of power transmission line.
NIOC's plan calls for installation of a gas treatment plant adjacent to the existing NGL 700/800 gas processing plants between Ahwaz, Mansuri, and Marun oil fields to treat gathered sour gas. The plant would use a diethanol-amine process and polishing unit to bring gas specifications to less than 4 ppm by volume hydrogen sulfide and 0.4 mol % carbon dioxide with total organic sulfur of 225 ppm by volume.
A 96 km, 12 in. pipeline would carry acid gas from compression and dehydration units at the sweetening plant to the Razi chemical complex. Sweetened gas would flow to the existing NGL plants for liquids recovery. n
The U.S. has waged its anti-Iran campaign alone. The European Union has refused to honor the U.S. trade embargo and strongly opposed secondary sanctions the U.S. Senate passed at yearend 1995.
This is the first of a two part article on Iran's campaign to rebuild its petroleum industry. Next: downstream projects.
U.S., Canadian pipeline projects advancing
Plans for gas pipeline construction programs are moving ahead on the U.S.-Canadian East Coast and in the U.S. Rocky Mountains.
Here are the latest developments:
* A group of companies asked the U.S. Federal Energy Regulatory Commission to approve first phase construction plans for a jointly owned, U.S.-Canadian pipeline.
Sponsors of the Maritimes & Northeast pipeline project propose to lay a 630 mile system to deliver gas from the Sable Island area off Nova Scotia to customers in southern Maine and New Hampshire. As much as 400 MMcfd could begin flowing on the system by November 1999.
* Wyoming Interstate Company Ltd. (WIC), the Rocky Mountain natural gas partnership of Coastal Corp., Houston, said results of an open season for new transportation capacity were so successful it intends to move forward immediately with system expansion.
Owned by two Coastal subsidiaries, WIC is the central segment of the Trailblazer Pipeline System, an 800 mile line stretching from Southwest Wyoming to Central Nebraska.
Gas projects dominate U.S. and Canadian pipeline plans involving line construction in 1996 and beyond. Current plans call for more than 3,800 miles of gas line to be laid in the U.S. and 2,800 miles in Canada (see table, OGJ, Feb. 5, p. 31).
East Coast
The proposed Maritimes & Northeast pipeline is to cross parts of Nova Scotia, New Brunswick, Maine, and New Hampshire before tying into the U.S. pipeline grid in Massachusetts.
Phase I of the system would enable sponsors to ship as much as 60 MMcfd through a 64 mile, 24 in. line between Dracut, Mass., and Wells, Me.
George Mazanec, vice-chairman of PanEnergy Corp. and chairman of the Maritimes & Northeast pipeline management committee, said Phase I transportation services will increase gas market competition in southern Maine and New Hampshire by boosting access in the region to new supplies and suppliers and cost effective, flexible gas services.
Phase I construction is supported by binding precedent agreements for long term transportation services with Mobil Natural Gas Inc. and PanEnergy Gas Services Inc., both gas marketing companies. Parent companies of the two gas marketing units last month disclosed they had signed a nonbinding letter of intent to combine marketing operations into a new joint venture.
Affiliates of Maritimes & Northeast sponsors PanEnergy Corp., Westcoast Energy Inc., Mobil Oil Corp., and Eastern Enterprises at the end of last month formed Maritimes & Northeast Pipeline LLC (Mnpllc) to build and own the U.S. portion of the system.
The group also chose PanEnergy units to manage and operate the pipeline and is developing agreements to cover relationships and responsibilities on the Canadian portion of the system.
PanEnergy and Westcoast each own a 32.5% interest in Mnpllc, Mobil 25%, and Eastern Enterprises 10%. Mobil's interest in the pipeline project includes 10% previously held by Shell Canada Ltd.
PanEnergy, through operating units, is to be responsible for overall development of the pipeline project and directly responsible for the U.S. portion of the system. Westcoast Energy will be responsible for developing the project's Canadian facilities.
Meantime, Sable Island project producers Mobil Oil Canada Properties, Shell Canada, Petro-Canada, Imperial Oil Resources Ltd., and Nova Scotia Resources Ltd. continue predevelopment activities on the Scotian Shelf, where Sable Island reserves are estimated at 3 tcf.
Rocky Mountains
"The strong response from producers for expanded transportation capacity out of Wyoming exceeded our expectations," said Jon R. Whitney, president and chief executive officer of WIC general partner CIG Gas Supply Co.
Bids for 812 MMcfd of additional firm capacity on WIC came from 21 shippers by the close of the open season Jan. 31. More than half were at maximum rates for terms of 10 years or greater.
Coastal's Colorado Interstate Gas Co. (CIG) also conducted an open season on its Wind River lateral that ended Feb. 12.
"The specific size of the WIC expansion will be determined in March, at which time all conditions in bids we received are to have been met and we will have finalized the precedent agreements," said Whitney, who also is president and chief executive officer of CIG.
"By early March, the open season on CIG's Wind River Lateral will have been completed, giving us further evidence of the amount of additional capacity that is needed. Nonetheless, it is clear that capacity on WIC will be expanded significantly beyond its current 500 bcfd."
WIC and the downstream Trailblazer segment can be expanded by simply adding compression, Whitney said.
Copyright 1996 Oil & Gas Journal. All Rights Reserved.
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