Nearing completion at Jose, an industrial complex on Venezuela's eastern Caribbean coast near Barcelona, is a heavy crude upgrader that is part of a $4.2 billion integrated upstream and downstream project. One-third of the investment is for the initial 250 wells and main production station near San Diego de Cabrutica in the Orinoco heavy-oil belt, while the other two-thirds are for the upgrader, storage, and export facilities at Jose.
Sincrudos de Oriente Sincor CA operates this project for producing 8.5° gravity crude, transporting it by a 200-km pipeline to Jose and upgrading it to a 32° gravity crude for export (Fig. 1).
Sincor calls the synthetic 32° gravity crude, Zuata Sweet, and plans to market it beginning in first quarter 2002.
Over its 35-year contract life, the project plans to produce the 8.5° gravity crude at a plateau of 200,000 b/d that, when diluted with a light naphtha, will yield a 17° gravity, 270,000- b/d feed into the upgrader. The upgrader is designed to produced about 180,000 b/d of Zuata Sweet for export.
Sincor expects to start the upgrader in December 2001, with commercial lifting starting in February 2002.
Sincor also has under construction a $194-million solids terminal for exporting the 6,000 tonnes/day of petroleum coke and 900 tonnes/day of sulfur produced in the upgrading process. It prefers to sell the sulfur in a liquid form, although initially solid sulfur may be the first product sold. The facility's design allows Sincor to switch from solid to liquid sulfur as dictated by market conditions.
In March 2001, Sincor signed 10-year agreements with TCP Petcoke Corp. and SSM Petcoke LLC, both based in the US, for the sale of coke.
Sincor began development drilling in the San Diego field in September 1999 and, since December 2000, has been producing about 40,000 b/d of heavy oil diluted with 25,000 b/d of Mesa crude to obtain a 16° gravity export stream.
On Jan. 30, 2001, Sincor shipped the first 600,000 bbl of the 16° gravity crude to US Gulf Coast.
Partners in Sincor are TotalFinaElf SA, 47%; Petróleos de Venezuela SA (PDVSA), 38%; and Statoil AS, 15%.
Orinoco belt
According to PDVSA, various multinational companies began exploring the Orinoco heavy-oil belt and drilling the first wells in the 1930s. But because of the low gravity, highly viscous crude, most interest in this area faded until the late 1970s and early 1980s when PDVSA through its affiliates (Maraven, Meneven, Lagoven, and Corpoven) undertook intensive exploration and evaluation that included drilling about 1,000 wells.
PDVSA estimates that the 54,000 sq km Orinoco area contains 1.2 trillion bbl of oil in place of which 100-300 billion bbl might ultimately be recovered.
These reserves are distribute in the Machete, Zuata, Hamaca, and Cerro Negro areas and four strategic alliances have been formed to exploit portions of these areas (Fig. 2).
PDVSA's affiliates in 1991 began negotiations with foreign oil companies, in accordance with the Venezuelan "Apertura" plan, to form these strategic associations for exploiting the heavy oil from the shallow Oficina formation. The agreements included a 34% corporate tax and a reduced royalty rate.
For instance, during the first 9 years of upgrader operations, Sincor's royalty will be 1%. Afterwards, the royalty will increase to the standard 16.7%.
Sincor currently pays a 16.7% royalty during the initial production phase prior to upgrader start up.
Some of the technology developed during the 1990s that played a key role in allowing these vast crude resources finally to be developed included 3D seismic, cold production with horizontal wells, drilling from clusters with built-for-purpose rigs, and advances in progressing cavity pumps (PCP).
Sincor says previous attempts to produce the wells with vertical wells and cold production proved uneconomic because of the relatively low 200-400 b/d/well initial producing rates, the high density of wells needed, and large investments. Such technologies as cyclic-steam production with vertical wells, although improving the productivity to 900-1,200 bo/d/well, were also too costly, requiring sizable investments and incurring high operating expenses.
Jean-Michel Gires, TotalFinaElf representative in Venezuela, says Total made the decision to go ahead with the project in 1998 when prices for this crude were $7-8/bbl. He says the current estimate is that the technical cost of the project will be less than $7/bbl with a breakeven point of less than $10/bbl.
Sincor expects Zuata Sweet will be sold at about a $0.50/bbl discount to West Texas Intermediate, FOB Jose.
Sincor's Zuata area
Sincor performed preliminary studies of the Zuata area from 1992 to 1996, with the Venezuela's congress approving the conceptual studies, production scheme, and the extent of Sincor's exploitation area in 1993. This was followed by basic engineering and an appraisal program that included a 3D seismic pilot and the drilling and testing of three vertical and three horizontal wells in 1997-98. The associ ation agreement was finalized in November 1997.
Sincor ran a full field 3D seismic survey in 1998 and also during this time awarded the engineering, procurement, and construction contracts and determined the financing, which included a $1.2 billion loan.
Development drilling started in September 1999, with early production of 40,000 bo/d of heavy oil starting in December 2000.
During early production, Sincor dilutes the produced crude with 25,000 bo/d of 30° gravity Mesa crude, a blend of crudes produced by PDVSA northeast of the Zuata area.
Sincor estimates that oil in place in its 500 sq km Zuata production area is about 38 billion bbl of 8-10° gravity oil in shallow Oficina formation sands at depths between 500-600 m. Over 35 years, it plans to recover 2.4 billion bbl or 6.5% of the oil in place.
Sincor describes its area as containing very soft unconsolidated, Miocene age, reservoir sands that are either meandering channel sands formed within a major deltaic deposit or fluvial deposits dominated by braided streams. The overall structure dips an average 2° towards the north and northeast.
It says the northeast area has a more complete stratigraphic column, while the south and southwest areas have had more erosion. Faulting is not a major concern in the area.
In developing the reservoirs, Sincor has found the geology more complex than originally assumed. It describes the meandering channel sands as sometimes having sand bodies with limited lateral and vertical continuity, resulting in laterally discontinuous reservoirs. Because of these discontinuities, it some times has to alter the planned well path while drilling these sands.
The braided stream sands, on the other hand, are more continuous and Sincor has concentrated on developing these fluvial deposits first. These reservoirs have 29-34% porosities and up to 90 ft net pay.
To date, Sincor has seen in dedicated observation wells only a 1-psi pressure drop from the initial reservoir pressure of 631 psi even after producing about 10 million bbl from the area. Its analysis indicates that solution drive with a foamy oil effect is the primary reservoir drive mechanism. The foamy oil effect is caused by microbubbles of gas trapped in the heavy oil.
It says other mechanisms that may be influencing recovery are reservoir compaction and a possible pressure support from the aquifer, but more production history will be needed to define their influence on ultimate recovery.
Sincor describes the foamy oil effect as reducing the gas saturation near the producing wellbores, thus increasing the solution gas effect. The oil viscosity at bottomhole conditions is 2,000-3,000 cp and increases at surface to 80,000 cp. Sincor studies have shown that the bubblepoint pressure is the same as the initial reservoir pressure.
Because of the unconsolidated sands and heavy oil, Sincor recognizes some uncertainty in determining formation permeability. From one 450-hr pressure buildup, it has calculated a 28-darcy average permeability, and indications are that reservoir permeability varies between 15 and 40 darcies.
Drilling, completing
For drilling wells, Sincor uses a multidiscipline integration at the planning stage coupled with real-time monitoring from multiple locations.
It batch drills wells from well clusters or pads (Fig. 3) with purpose-built rigs that can be skidded from well to well without having to rig down the mast or lay down drill pipe. Equipment used includes a top drive, skidding and moving system, logging while drilling (LWD), measurement while drilling (MWD), heavy-weight drill pipe, desander, desilter, centrifuge, and shale shakers (four in parallel).
To drill the wells, it uses a low-weight polymer mud. Each cluster developed to date has 4 to 24 producing wells.
Sincor initially planned to drill wells in a butterfly pattern with 1.4-km horizontal laterals but now has gone to a flower pattern with up to 1.7-km horizontal laterals.
Each rig site transmits real-time LWD and surface drilling parameter data via satellite, 300 km to Sincor's Caracas headquarters for analysis and viewing of the well trajectory with LWD curves on the seismic section.
With this information, teams both in Caracas and at the rig site can redefine the well trajectory. Sincor says sidetracks are not expensive and typically only 6 hr of additional drilling are needed to find better pay.
Sincor uses LWD gamma ray and resistivity curves with predefined cut-offs to determine net pay drilled. It says drilling results average above 85% net pay.
A typical well has a 16-in. surface hole to about 400 ft measured depth (MD), with 133/8-in. casing cemented in the hole. The next section is a vertical 121/4-in. hole to a kick-off-point (KOP), about 900 ft above the target sand. A build section follows with average build rates of 5-6°. The 121/4-in. section is completed with cemented 95/8-in. casing.
Sincor uses a batch-drilling strategy that consists of drilling all the 16-in. hole sections for a particular well cluster, followed by all 121/4-in. build sections, and then all 81/2-in. horizontal laterals.
It indicates typical drilling times are 2 days for the 121/4-in. build sections, including drilling, running casing, cementing, and skidding rig, and 3-4 four days for the 81/2-in. lateral sections, including drilling, running liner, and skidding rig.
A 7-in. liner with 0.02-in. slots is set in the 81/2-in. lateral.
By the end of 2001, Sincor expects to have 158 active wells on production from 17 well clusters. It will then have drilled 28 observation wells, 26 needle wells, 78 slanted wells, 237 completed wells, 244 horizontal drains, 284 intermediate holes, and 338 top holes.
Through September 2001, it says it has drilled 2 million ft of hole, 50% of which were horizontal laterals.
It drills the observation wells in the center of the well pad to determine the sand depth; then slant wells are drilled 800-1,000 m from the cluster location to help establish the horizontal lateral path in the producing wells.
Sincor has drilled some dual multilaterals and "fish bone" wells but says it has not seen any clear advantage for that type of well geometry.
Over the life of the project, Sincor expects to drill about 1,200-1,500 producing wells with horizontal drains.
Production operations
Sincor has found that cold production with horizontal wells pumped with PCPs can produce up to 3,000 bo/d/well. It indicates some wells have a capacity to produce up to 5,000 bo/d but are limited to the PCPs 3,000 bo/d limit.
Depending on a well's productivity, Sincor runs PCPs with a 5 b/d/rpm, 9.5 b/d/rpm, or 12 b/d/rpm capacity and varies pump speed to 100-400 rpm. It has standardized on one type of top-drive surface motor (Fig. 4) and on 11/4-in. sucker rods.
The PCP motors have variable-frequency drives, and average well production is between 1,000-2,000 bo/d. Produced GOR varies from 50 to 250 scf/bbl.
Sincor sets the PCPs in the 70° build section of the well. Production is through 23/8-in. tubing.
It says that to date no sand production has occurred and the wells have only very limited water production. It flows the well annuli continuously to flowlines.
At each cluster, twin-screw multiphase pumps (MPP) boost production to the main production station and a multiphase meter determines fluids produced during well tests. The clusters also include provisions for injecting corrosion inhibitor and controls for regulating diluent injection for each well.
Sincor has equipped the PCPs and MPPs for either remote or local restart and stop, although well tests have to be started manually at the clusters.
Emergency-shutdown valves are at each cluster and main station inlet. The clusters have no utilities other than electricity. A 35.2-kv power distribution system delivers to the clusters the power generated at the main production station.
An unburied network of flowlines gathers the crude into a 16-in. main oil trunk line that transports production to the main production station. Diluent is distributed from a main 12-in. line.
An optic fiber line runs along the power distribution network and transmits data from the wells and clusters. Sincor has installed downhole pressure and temperature sensors in horizontal laterals and observation wells.
The produced crude is currently being mixed with the Mesa crude at the wellhead, downhole above the PCP pump, and at the toe of the horizontal drain.
Sincor has found that injecting diluent at the toe lowers the pressure drop at the formation and can increase well productivity by up to 50%.
A naphtha diluent will replace the Mesa crude once the upgrader starts up.
Main station
Sincor's main production station, near San Diego de Cabrutica, has two trains for treating the 210,000 b/d of 8.5° gravity heavy oil that will be diluted with 75,800 b/d of 47.8° gravity naphtha (Fig. 6).
The facility's design can handle 21,000 b/d of produced water.
The diluted crude will have a 17° gravity with an 11-psi RVP. During the initial phase with Mesa crude diluent, the diluted crude has 16° gravity. Inlet pipeline temperature is 79° C.
Each 150,000-b/d process train consists of a slug catcher, heater feed pump, produced water-oil shell and tubes heat exchangers, oil-oil plate heat exchanger, radiation plus conversion heater, high temperature separator, dehydration pump, and electrostatic dehydrator (Fig. 7).
The facility design allows diluent to be received in batches at a maximum flow of 142,000 b/d through a 16 in., 25-km buried pipeline from the facilities at Petrozuata's pipeline station. The main station has a 100,000-bbl diluent holding tank with an internal floating roof.
From the tank, diluent is pumped to the clusters, although the main station is equipped to inject additional diluent to correct the crude gravity leaving the facility.
The main station also has a 100,000-bbl off-spec tank and a low-pressure flare. The off-spec tank has a fixed roof, and gas blanketing prevents oxygen entry into the tank.
Three 26-Mw gas turbines (GE Frame 5) capable of being run on either diesel or fuel gas generate the electricity for both the main station and well clusters.
The export pumps, with a 315,000-b/d capacity, continuously pump diluted crude through a 25 km, 26-in. pipeline to two 220,00-bbl Sincor tanks at Petrozuata CA's production station. Petrozuata is another strategic alliance developing heavy oil in the Zuata area.
Sincor has an agreement to transport its crude and diluent through pipelines shared with Petrozuata.
Petrozuata pumps Sincor's diluted crude in batches through its 200 km, 36-in. line to Jose. Diluent from Jose is batched through a 20-in line to Petrozuata's production station before it enters a 16-in. line to Sincor's main production station.
One problem faced by Sincor in the field is the sandy soil, and any ground clearance leads to erosion problems during the wet season. Sincor is re-grassing all areas that were cleared during the drilling and construction phases and uses special coconut-fiber matting to stabilize the seeds.
Another environmental concern is the treatment of drilling and product wastes, which is more complicated in the case of heavy crude. Sincor centrifuges the drilling mud to eliminate the liquids. The remaining solid waste is then mixed with soil until the overall hydrocarbons content is less than 2% before it is placed in monitored storage facilities equipped with a special drainage system to protect the water table.
Sincor treats the produced liquids and re-injects them into deeper zones.
Upgrader
Sincor compares the low-sulfur, light Zuata sweet crude from the upgrader (Fig. 7) to Nigerian Forcados crude. A preliminary assay, completed in December 2000, on a synthesized Zuata Sweet showed that the crude has a sizeable middle-distillate fraction (53.5 vol %) with much less naphtha than Forcados, Brent, and WTI crudes, and no residual oil. The average sulfur content of the diesel fraction is 0.05 wt %.
The assay suggests a 33.6 vol % yield of vacuum gas oil (VGO). VGO sulfur contents are less than 0.15 wt %, and nitrogen contents are less than 0.1 wt %. Sincor estimates that the worldwide market for this type of crude is about 2 million b/d in sweet refineries, with potential markets in:
- US Gulf Coast, East Coast, and Midcontinent: 650,000-700,000 b/d.
- Northwest Europe: 650,000-700,000 b/d.
- Asia-Pacific: 250,000-300,000 b/d.
- Latin America and Eastern Canada: 200,000-250,000 b/d.
Gires of TotalFinalElf says Sincor initially plans to enter into short-term sales agreements with one or two Gulf of Mexico refineries, but as the crude becomes more accepted in the market it will be sold on the spot market.
The upgrader process flow (Fig. 8) includes atmospheric distillation, vacuum distillation, delayed coking, mild hydrocracking, and hydrotreating . At peak construction, the upgrader project has employed 13,000 persons.
Besides the 180,000 b/d of Zuata Sweet, the upgrader will produce 6,000 tonnes/day of coke, 900 tonnes/day of sulfur, and 70,000 b/d of 47° gravity naphtha diluent that is returned to the San Diego field.
Sincor says that the produced "shot" coke will be sold primarily to power generators or cement plants. Its quality is not high enough for other uses.
PDVSA's liquid loading facility will handle the exports of Zuata Sweet, and Sincor is building the sulfur and coke handling and storage facilities. These products will be loaded on ships from Pequiven facilities located besides the jetty.
Under construction across the road from the upgrader is a closed-conveyer-belt system to move 2,000 tonnes/hr of coke to the jetty. Sincor also will have a 1-million tonne coke storage area, a 90,000-tonne dry sulfur yard, and storage tanks for 45,000 tonnes of liquid sulfur. The sulfur tanks need to be heated in order for the sulfur to remain liquid.
To suppress coke dust, Sincor will be installing a sophisticated water-spray system.
Sincor says the delayed-coking unit is the most important part of the upgrader. It has a design capacity of 89,000 b/sd of vacuum residue with a 19-hr cycle. The unit consists of six 28-ft ID coke drums and three fired heaters and has a 106,800-b/sd rated capacity for fresh feed with a 16-hr cycle time. Foster Wheeler USA Corp. (FWUSA) designed and built the unit.
Sincor says the delayed coker is the second largest in the world, being slightly smaller than a coker in India.
A simple but extensive coke drum interlock logic and sequencing system greatly enhanced the safety and operation of the unit, according to Luis Marquez, Sincor's commissioning site leader.
He says the coke drum interlock and sequence scheme minimizes or eliminates the likelihood of operational errors common in delayed-coking operations by means of a predetermined logic that verifies that all prerequisites and permissives have been satisfied for each step in the coke drum sequence, before any valve movement.
In developing the system, the coke-drum logic was programmed into the digital control system to be monitored by the control room operator. The system also provides some feedback information received from the field via pushbutton stations, which are part of the logic. Each motor-operated valve involved in the coke-drum sequence has integral actuator limit switches, which provide the required information to the logic.
The control room operator by means of graphics and overlays monitors the sequence. The graphics allow the operator to proceed through the coker sequence, while the overlays allow or disallow the manipulation of the devices based on the status of the sequence logic.
Table 1 lists the inital capacity of the upgrader units. Through debottlenecking and modifications, Sincor expects the capacity, as shown in the future column, to increase.
Olav Kr. Birkeland, general manager of the upgrader, emphasized that an important objective of Sincor was to train Venezuelan operators and maintenance technicians for the start up and safe and efficient operation of the upgrader.
Sincor held its recruitment program throughout Venezuela and selected participants for training as operators that included:
- College-trained technicians or engineers who had completed 3 years of study.
- Specialized graduates in chemistry, mechanics, oil processing, electricity, and instrumentation.
- All levels of previous work experience.
- Average age: 25 years.
- Gender distribution of 119 male and 35 female.
Sincor's target for the operational phase is to have 85% Venezuelan nationals initially, increasing to 100% in 18 months. It will operate the upgrader with about 320 Sincor employees and 150 contract maintenance workers.
Birkeland expects that the upgrader will only need a turnaround every 4 years.
Future
Although existing Orinoco production and upgrading operations have plans for future expansion, Venezuela's draft of a new hydrocarbon law has much tougher fiscal provisions than the previous agreements. The draft requires a 51% PDVSA interest in new projects and a 30% royalty. Unless changes are made, these terms may become law in November 2001.
Jorge Carnevali, PDVSA's managing director-joint ventures, said that operators would prefer more flexibility in the law. Instead of a fixed royalty and PDVSA interest, they prefer to negotiate the values, depending on project economics.
He further said that Venezuela needed the higher royalties because production from such projects as those in the Orinoco is protected from being reduced because of a lower OPEC quota.
In other words, as the Orinoco projects come on stream, they back out PDVSA's production if Venezuela's OPEC quota is not increased, which has been the case during the last year. The Orinoco production, with its lower royalty during the early upgrading years, thus reduces revenues to Venezuela.
He also expects that in the future more emphasis will be placed on synergies between projects and on projects that add value to the export stream by producing a greater variety of refined products.
