John L. Kennedy
Editor
The first of two trains of an oil and gas processing plant designed to handle high pressure corrosive wellstreams from the Soviet Union's giant Tengiz field is scheduled for start-up later this year.
Train two in this first plant to be built in the field is under way, and additional multitrain plants are planned.
Tengiz, near the northeast coast of the Caspian Sea (Fig. 1), may be the largest oil field found in the U.S.S.R. since the 1965 discovery of Samotlor in Western Siberia.
Getting Tengiz onstream will be some help in slowing the decline in Soviet oil production.
Production dropped 2.5% in 1989. And for the first 5 months of 1990, the Soviets reported a further 5% decrease.
Many of the fields in Western Siberia where two thirds of Soviet oil is produced are in decline and new fields are not filling the gap.
Getting Tengiz near production has not been easy. Construction of the processing plant was delayed 2 years because of local concerns about handling high-H2S gas from the field-H2S concentrations as high as 25%.
EXPANSION SCHEDULE
Each processing train at Tengiz 1 will handle full wellstreams from wells in the field. Each train includes separation and stabilization; gas purification; sulfur production; and gas liquids recovery.
Stabilized oil and dry gas will be shipped from the plant by pipeline, and sulfur and LPG will move by rail.
Composition of the approximately 50 multiphase wellstreams that will converge at the inlet header will vary, making estimates of feed volume difficult.
But expected annual output from Tengiz 1 plant's two trains is 3 million tons of stabilized 0.805 density oil (about 70,300 b/sd); 77 million cu m (8.1 MMcfd) of dry gas; and about 500,000 tons of sulfur.
Natural gas liquids will also be produced.
The first train was built by the consortium "LLL," made up of Lafarge Coppee Lavalin S.A., Litwin S.A., and Lurgi S.A. The consortium is also supervising construction of the second train.
During a visit to the plant in late spring, the first train was 90% complete and civil work was complete on the second train, scheduled to begin operation in the fall of 1992.
The first additional capacity from plants now in the early design stage is planned for commissioning in 1993, according to a Soviet spokesman. They likely will be of the same configuration as Tengiz 1.
Total workforce at the new plant-including auxiliary personnel such as instrument, electrical, and mechanical specialists and repair teams-will near 1,500, according to a plant spokesman. Operations manpower on each shift will likely be 40-50.
Earlier this year, Chevron signed an agreement with the Soviets to study the feasibility of adding Tengiz field to its joint venture.
PROCESSING SCHEME
Full wellstreams will enter the plant's three stage separation system in which the first stage will operate at about 65 bar (955 psi). The second stage separator will operate at 25 bar (368 psi), and the third stage at 7.7 bar (113 psi). Fig. 2 is a simplified flow schematic.
The liquid hydrocarbon stream from the third stage separator is desalted before going to the stabilizer; water from the separators goes to a sour water stripper.
The crude oil stabilizer will operate at 7.7-8.0 bar (113-118 psi) and 40-172 C.
Each train at Tengiz will have two diethanolamine (DEA) contactors. One takes gas from the high pressure inlet separator and is designed to operate at about 64.5 bar (948 psi). The other, operating at about 24.5 bar (360 psi), is fed by gas from the other two separation stages.
Demethanizer, deethanizer, and depropanizer make pipeline gas, ethane, propane, and a broad fraction product. In the beginning, ethane will be mixed with the pipeline gas, according to a Soviet spokesman. But petrochemical plant expansions farther south at Shevchenko will provide an outlet for ethane soon.
A Claus unit will provide 96% conversion of H2S to sulfur and the Sulfreen process is used for gas cleanup. A 210 m flare stack is part of the sulfur recovery plant. Estimated discharge pf SO2 to the air from the first train is 10,000 tons/year, according to a spokesman at the plant.
Both liquid and solid sulfur can be produced, but the risk of sand or dust contamination may prevent production of solid sulfur. A granular sulfur product may be produced in the future.
A central control room has redundant control and monitoring systems, and each unit within the plant has its own local control. A special system monitors H2S and natural gas in the atmosphere at critical points around the plant and can automatically shut down a given unit if a gas leak is detected.
And the chief plant operator can shut down the entire plant from the central control room in case of a serious emergency.
Plant vessels and piping are designed for H2S service, according to a spokesman. Corrosion inhibitors and stationary coupons are used in the wells; data on corrosion levels are sent from wells to the plant's central control room.
FIELD AND WELLS
Although Tengiz was discovered more than 10 years ago, no wells could be produced until a treatment plant was onstream. Even testing was minimal until 1981 due to a lack of equipment to handle the high H2S wellstreams.
Tengiz reserve estimates vary widely. Soviet authorities have estimated oil in place in the 140 sq km anticlinal fold at as much as 25 billion bbl, according to Chevron. Another estimate put recoverable reserves at 6-7 billion bbl.
Chevron's recent agreement will study the feasibility of entering into a joint venture with Tengizneftegaz to explore and produce in an 8,900 sq mile area that includes Tengiz (OGJ, June 11, 1990, p. 18).
To date, about 40 wells have been completed. Plans are to have a total of 85 wells in the field by 1995.
Average well depth is about 4,500 m. The deepest well to date is reported to be 5,414 m, but deeper wells are planned and under way. Even the deepest well so far did not encounter water, so none is expected when the wells go onstream.
Estimates of pay thickness vary, but the reservoir is at least 400 m thick, according to Soviet engineers. Porosity of the producing layer ranges from 1 to 25% and averages 6-7%. Permeability is only about 0.1 md; oil production is from fractures in the chalk layers.
First wells in the field were perforated and tested briefly,
then cemented because equipment wasn't available to handle the corrosive wellstreams. Later wells were perforated, tested, and completed. Those wells are ready to be turned into the new plant, according to a Soviet spokesman.
Early spacing was 1.4-1.5 km between wells; then spacing was decreased to 1.0-1.1 km. Now spacing is typically 700 m between wells. Some wells were cored continuously, others just in intervals where additional information was needed.
Up to 2 years have been required to drill some Tengiz wells.
WELL DESIGN
Tengiz completions include four casing strings (Fig. 3). Typically, a 16-in. surface string is set to a depth of 500 m, then a 13-in. string is set to a depth of 2,500-3,200 m.
A 9 in. or 10-in. string is normally run from 3,900-4,200 m to surface and the 7-in. production string to TD of 4,200-4,500 m.
Drilling mud weights are typically 2.1 g/cc (17.5 ppg).
A corrosion inhibitor valve is run in the tubing string which is set in a packer above the producing interval. Inhibitor is injected down the casing/tubing annulus and into the tubing through the inhibitor valve. Inhibitor is also injected into the flow line, and corrosion sensors at the well are monitored at the processing plant.
The section of the tubing and the section of the production casing below the inhibitor valve are stainless steel.
The rest of these two strings, as well as the 9 in. or 10-in. string, are 90-ksi yield strength pipe.
Flow rates are expected to average 300-450 tons/day (2,200-3,300 b/d), according to a spokesman in the field. Gas/oil ratio is about 500 cu m/ton (2,400 cu ft/bbl). Static wellhead pressures are about 560-570 atm (about 8,300 psi); flowing wellhead pressures typically are 400-500 atm (5,800-7,350 psi).
In addition to corrosion, several other parameters are sensed at the well and monitored at the central control room at the processing plant, including pressure, temperature, power consumption, choke position, tubing and casing pressure, and inhibitor pump operation. Spare capacity has been built into the telemetry system to accommodate other data if necessary.
During the Journal's visit to the field earlier this year, Soviet officials were reluctant to estimate reserves. An oil/water contact has not been located, and there is no production history. So it may be several years before a reliable estimate can be made.
A Soviet spokesman in the field said that plans are to operate the field without repressuring until the year 2015. A study is under way to determine what should be injected-water or gas-after that.
If gas injection will provide the best recovery, injection would likely start when reservoir pressure reaches about 450 atm (6,600 psi), according to the spokesman. If water injection offers the best results, it would not be begun until reservoir pressure declines to the saturation pressure.
Soviet engineers say the reservoir pressure is currently about 850 atm (12,500 psi) and saturation pressure is estimated to be 250-270 atm (3,675-3,970 psi).
OTHER FIELDS
There are a number of other fields in the area around the northeastern shore of the Caspian Sea, Several along the seashore contain very high viscosity crude-300-1,000 cp-and require some type of thermal assistance in order to produce commercially.
These fields are from 300 to 2,000 m deep.
A study was under way earlier this year to determine how to produce these heavy oil reservoirs.
Exploration is also being done elsewhere around the Tengiz structure in 10 or 12 different areas.
Some wells could be more productive-and indicate larger reservoirs-than those in Tengiz, according to a spokesman.
ACKNOWLEDGMENT
The help of Mikhail Gudyrin, Tengizneftegaz chief geologist, and Mr. Makhoshvily, Tengiz 1 plant director, in preparing this article is much appreciated; as is the help of Partec Lavalin Inc, Also appreciated are the translation services of Borisov Igor, Albert Drubkin, and Tamara Filippova.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.
